Phillips 66 - Annual Report: 2012 (Form 10-K)

Closing Stock Price at December 31, 2012

Closing Stock Price at January 31, 2013

Number of Stockholders of Record at January 31, 2013



2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)
[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended	December 31, 2012
	OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



For the transition period from		to
	Commission file number: 001-35349

Phillips 66

(Exact name of registrant as specified in its charter)



Delaware		45-3779385
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

3010 Briarpark Drive, Houston, Texas 77042

(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: 281-293-6600



Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Name of each exchange on which registered
Common Stock, $.01 Par Value		New York Stock Exchange



Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.				[x] Yes [ ] No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.				[ ] Yes [x] No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.				[x] Yes [ ] No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).				[x] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [x]	Accelerated filer [ ]	Non-accelerated filer [ ]	Smaller reporting company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).				[ ] Yes [x] No

The aggregate market value of common stock held by non-affiliates of the registrant on June 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, based on the closing price on that date of $33.24, was $20.8 billion. The registrant, solely for the purpose of this required presentation, had deemed its Board of Directors and executive officers to be affiliates, and deducted their stockholdings in determining the aggregate market value.

The registrant had 621,509,611 shares of common stock outstanding at January 31, 2013.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 8, 2013 (Part III)

Table of Contents

Index to Financial Statements

TABLE OF CONTENTS

Item	Page

PART I

1 and 2. Business and Properties	1
Corporate Structure	1
Segment and Geographic Information	2
Refining and Marketing (R&M)	2
Midstream	10
Chemicals	12
Technology Development	14
Competition	14
General	14
1A. Risk Factors	16
1B. Unresolved Staff Comments	21
3. Legal Proceedings	22
4. Mine Safety Disclosures	23
Executive Officers of the Registrant	24

PART II

5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
6. Selected Financial Data	26
7. Management's Discussion and Analysis of Financial Condition and Results of Operations	27
7A. Quantitative and Qualitative Disclosures About Market Risk	50
Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995	52
8. Financial Statements and Supplementary Data	54
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	112
9A. Controls and Procedures	112
9B. Other Information	112

PART III

10. Directors, Executive Officers and Corporate Governance	113
11. Executive Compensation	113
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	113
13. Certain Relationships and Related Transactions, and Director Independence	113
14. Principal Accounting Fees and Services	113

PART IV

15. Exhibits, Financial Statement Schedules	114
Signatures	138

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Index to Financial Statements

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “Phillips 66” are used in this report to refer to the businesses of Phillips 66 and its consolidated subsidiaries. This Annual Report on Form 10-K contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company's disclosures under the heading “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE 'SAFE HARBOR' PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 52.

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

Phillips 66, headquartered in Houston, Texas, was incorporated in Delaware on November 10, 2011, in connection with, and in anticipation of, a restructuring of ConocoPhillips. On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement between ConocoPhillips and Phillips 66, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips shareholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. A registration statement on Form 10, as amended through the time of its effectiveness, describing the Separation was filed by Phillips 66 with the U.S. Securities and Exchange Commission (SEC) and was declared effective on April 12, 2012 (the Form 10). On May 1, 2012, Phillips 66 stock began trading “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

We have organized our reporting structure based on the grouping of similar products and services, resulting in three operating segments:


1)	R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. This segment also includes power generation operations. The R&M segment's “refining” and “marketing, specialties and other” operations are disclosed separately for supplemental reporting purposes.


2)	Midstream—This segment gathers, processes, transports and markets natural gas; and transports, fractionates and markets natural gas liquids (NGL) in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).


3)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).

At December 31, 2012, Phillips 66 had approximately 13,500 employees.

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Index to Financial Statements

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 26—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

REFINING AND MARKETING (R&M)

At December 31, 2012, our R&M segment represented 77 percent of Phillips 66's total assets. Our R&M segment primarily refines crude oil and other feedstocks into petroleum products (such as gasolines, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. This segment also engages in power generation activities. R&M has operations in the United States, Europe and Asia.

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Index to Financial Statements

Refining

The table below depicts information for each of our U.S. and international refineries at December 31, 2012:



				Thousands of Barrels Daily
Region/Refinery	Location	Interest		Net Crude Throughput Capacity		Net Clean Product Capacity**		Clean Product Yield Capability
Region/Refinery	Location	Interest		At December 31, 2012	Effective January 1, 2013	Gasolines	Distillates	Clean Product Yield Capability
Atlantic Basin/Europe
Bayway	Linden, NJ	100.00	%	238	238	145	115	90	%
Humber	N. Lincolnshire, United Kingdom	100.00		221	221	85	115	81
Whitegate	Cork, Ireland	100.00		71	71	15	30	65
MiRO*	Karlsruhe, Germany	18.75		58	58	25	25	85
				588	588

Gulf Coast
Alliance	Belle Chasse, LA	100.00		247	247	125	120	86
Lake Charles	Westlake, LA	100.00		239	239	90	115	70
Sweeny	Old Ocean, TX	100.00		247	247	125	120	87
				733	733

Central Corridor
Wood River	Roxana, IL	49.60		152	154	75	55	83
Borger	Borger, TX	49.60		72	72	50	25	89
Ponca City	Ponca City, OK	100.00		187	190	105	80	91
Billings	Billings, MT	100.00		58	59	35	25	89
				469	475

Western/Pacific
Ferndale	Ferndale, WA	100.00		100	101	55	30	75
Los Angeles	Carson/ Wilmington, CA	100.00		139	139	80	65	88
San Francisco	Arroyo Grande/San Francisco, CA	100.00		120	120	55	60	83
Melaka	Melaka, Malaysia	47.00		80	80	20	50	80
				439	440
				2,229	2,236

*Mineraloelraffinerie Oberrhein GmbH.

**Clean product capacities are maximum rates for each clean product category, independent of each other. They are not additive when calculating the clean product yield capability for each refinery.

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Index to Financial Statements

Primary crude oil characteristics and sources of crude oil for our refineries are as follows:



	Characteristics				Sources
	Sweet	Medium Sour	Heavy Sour	High TAN^*	United States	Canada	South America	Europe & Central Asia	Middle East & Africa
Bayway	l				l			l	l
Humber	l	l		l				l	l
Whitegate	l							l	l
MiRO	l	l						l	l
Alliance	l				l				l
Lake Charles	l	l	l	l	l		l
Sweeny	l		l	l	l		l		l
Wood River	l		l	l	l	l
Borger		l	l		l	l
Ponca City	l	l	l		l	l
Billings		l	l			l
Ferndale	l	l			l	l
Los Angeles		l	l	l	l	l	l		l
San Francisco	l	l	l	l	l				l
Melaka	l	l	l						l

*High TAN (Total Acid Number): acid content greater than or equal to 1.0 milligram of potassium hydroxide (KOH) per gram.

Atlantic Basin/Europe Region

Bayway Refinery

The Bayway Refinery is located on the New York Harbor in Linden, New Jersey. Bayway refining units include a fluid catalytic cracking unit, two hydrodesulfurization units, a reformer, alkylation unit and other processing equipment. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as petrochemical feedstocks, residual fuel oil and home heating oil. Refined products are distributed to East Coast customers by pipeline, barge, railcar and truck. The complex also includes a 775-million-pound-per-year polypropylene plant.

Humber Refinery

The Humber Refinery is located on the east coast of England in North Lincolnshire, United Kingdom. It produces a high percentage of transportation fuels, such as gasoline and diesel. Humber’s facilities encompass fluid catalytic cracking, thermal cracking and coking. The refinery has two coking units with associated calcining plants, which upgrade the heaviest part of the crude barrel and imported feedstocks into light oil products and high-value graphite and anode petroleum cokes. Humber is the only coking refinery in the United Kingdom and is one of the world’s largest producers of specialty graphite cokes and one of Europe’s largest anode coke producers. Approximately 50 percent of the light oils produced in the refinery are marketed in the United Kingdom, while the other products are exported to the rest of Europe and the United States.

Whitegate Refinery

The Whitegate Refinery is located in Cork, Ireland, and is Ireland’s only refinery. The refinery primarily produces transportation fuels, such as gasoline, diesel and fuel oil, which are distributed to the inland market, as well as being exported to Europe and the United States. We also operate a crude oil and products storage complex consisting of 7.5 million barrels of storage capacity and an offshore mooring buoy, located in Bantry Bay, about 80 miles southwest of the refinery in southern Cork County.

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Index to Financial Statements

MiRO Refinery

The Mineraloelraffinerie Oberrhein GmbH (MiRO) Refinery, located on the Rhine River in Karlsruhe in southwest Germany, is a joint venture in which we own an 18.75 percent interest. Facilities include three crude unit trains, fluid catalytic cracking, petroleum coking and calcining, hydrodesulfurization units, reformers, isomerization and aromatics recovery units, ethyl tert-butyl ether (ETBE) and alkylation units. MiRO produces a high percentage of transportation fuels, such as gasoline and diesel. Other products include petrochemical feedstocks, home heating oil, bitumen, and anode- and fuel-grade petroleum coke. Refined products are delivered to customers in southwest Germany, northern Switzerland and western Austria by truck, railcar and barge.

Trainer Refinery

In June 2012, we sold the Trainer Refinery and associated terminal and pipeline assets.

Gulf Coast Region

Alliance Refinery

The Alliance Refinery is located on the Mississippi River in Belle Chasse, Louisiana. The single-train facility includes fluid catalytic cracking units, hydrodesulfurization units, a reformer and aromatics unit, and a delayed coking unit. Alliance produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, home heating oil and anode petroleum coke. The majority of the refined products are distributed to customers in the southeastern and eastern United States through major common-carrier pipeline systems and by barge. Refined products are also sold into export markets through the refinery's marine terminal.

Lake Charles Refinery

The Lake Charles Refinery is located in Westlake, Louisiana. Its facilities include fluid catalytic cracking, hydrocracking, delayed coking and hydrodesulfurization units. The refinery produces a high percentage of transportation fuels, such as gasoline, off-road diesel and jet fuel, along with home heating oil. The majority of its refined products are distributed by truck, railcar, barge or major common-carrier pipelines to customers in the southeastern and eastern United States. Refined products can also be sold into export markets through the refinery’s marine terminal. Refinery facilities also include a specialty coker and calciner, which produce graphite petroleum coke for the steel industry.

Excel Paralubes

We own a 50 percent interest in Excel Paralubes, a joint venture which owns a hydrocracked lubricant base oil manufacturing plant located adjacent to the Lake Charles Refinery. The facility produces approximately 20,000 barrels per day of high-quality, clear hydrocracked base oils.

Sweeny Refinery

The Sweeny Refinery is located in Old Ocean, Texas, approximately 65 miles southwest of Houston. Refinery facilities include fluid catalytic cracking, delayed coking, alkylation, a continuous regeneration reformer and hydrodesulfurization units. The refinery receives crude oil primarily via tankers, through wholly and jointly owned terminals on the Gulf Coast, including a deepwater terminal at Freeport, Texas. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks and home heating oil. We operate nearby terminals and storage facilities, along with pipelines that connect these facilities to the refinery. Refined products are distributed throughout the Midwest and southeastern United States by pipeline, barge and railcar.

MSLP

Merey Sweeny, L.P. (MSLP) owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by ConocoPhillips and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which was exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal held hearings on the merits of the dispute in December 2012, and we expect a final ruling in the fourth quarter of 2013. Following the Separation, Phillips 66 generally indemnifies ConocoPhillips for liabilities, if any, arising out of the exercise of the call right or otherwise with respect to the joint venture or the refinery.

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Index to Financial Statements

Central Corridor Region

WRB Refining LP (WRB)

We are the operator and managing partner of WRB, which consists of the Wood River and Borger refineries.

Prior to the Separation, ConocoPhillips had two 50/50 North American business ventures with Cenovus Energy Inc. (Cenovus): a Canadian upstream general partnership, FCCL Partnership (FCCL), and a downstream U.S. limited partnership, WRB Refining LP. In accordance with the Separation and Distribution Agreement, ConocoPhillips retained its 50 percent interest in FCCL and a 0.4 percent interest in WRB, while contributing its remaining 49.6 percent interest in WRB to us in the Separation. We expect to purchase ConocoPhillips' 0.4 percent interest in WRB during 2013.

WRB’s gross processing capability of heavy Canadian or similar crudes ranges between 235,000 and 255,000 barrels per day after the completion of the coker and refining expansion (CORE) project at the Wood River Refinery, which occurred in late 2011.


•	Wood River Refinery

The Wood River Refinery is located in Roxana, Illinois, about 15 miles northeast of St. Louis, Missouri, at the convergence of the Mississippi and Missouri rivers. Operations include three distilling units, two fluid catalytic cracking units, hydrocracking, coking, reforming, hydrotreating and sulfur recovery. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petrochemical feedstocks, asphalt and coke. Finished product leaves Wood River by pipeline, rail, barge and truck. The CORE Project resulted in a 5 percent increase in clean product yield and doubled gross heavy crude oil capacity to between 200,000 and 220,000 barrels per day, dependent on the quality of available heavy crudes.


•	Borger Refinery

The Borger Refinery is located in Borger, Texas, in the Texas Panhandle, approximately 50 miles north of Amarillo. The refinery facilities encompass coking, fluid catalytic cracking, hydrodesulfurization and naphtha reforming, and a 45,000-barrel-per-day NGL fractionation facility. It produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel, as well as coke, NGL and solvents. Refined products are transported via pipelines from the refinery to West Texas, New Mexico, Colorado and the Midcontinent region.

In connection with the Separation, we entered into a put agreement and a feedstock right of first offer agreement with Cenovus. Under the put agreement, if Cenovus suffers a transportation constraint it cannot mitigate which threatens to shut in FCCL production, we will be required to purchase FCCL-produced crude oil from Cenovus, subject to a maximum daily volume amount and provided we have pipeline capacity available after meeting any other contractual obligations, at a price equal to the lower of fair market value or the “break even value” of such crude oil compared to other crude oils that could be processed at one of our refineries. Under the feedstock right of first offer agreement, if we plan to enter into a six-month or longer term agreement to acquire Canadian crude oil for the Wood River Refinery or the Borger Refinery, we will be required to first notify Cenovus and offer Cenovus the opportunity to supply FCCL-produced crude oil according to the specified terms.

Ponca City Refinery

The Ponca City Refinery is located in Ponca City, Oklahoma. Its facilities include fluid catalytic cracking, delayed coking and hydrodesulfurization units. It produces a full range of products, including gasoline, diesel, jet fuel, liquefied petroleum gas (LPG) and anode-grade petroleum coke. Finished petroleum products are primarily shipped by company-owned and common carrier pipelines to markets throughout the Midcontinent region.

Billings Refinery

The Billings Refinery is located in Billings, Montana. Its facilities include fluid catalytic cracking and hydrodesulfurization units, in addition to a delayed coker, which converts heavy, high-sulfur residue into higher-value light oils. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and aviation fuels, as well as fuel-grade petroleum coke. Finished petroleum products from the refinery are delivered by pipeline, railcar and truck. The pipelines transport most of the refined products to markets in Montana, Wyoming, Utah and Washington State.

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Index to Financial Statements

Western/Pacific Region

Ferndale Refinery

The Ferndale Refinery is located on Puget Sound in Ferndale, Washington, approximately 20 miles south of the U.S.-Canada border. Facilities include a fluid catalytic cracker, an alkylation unit, a diesel hydrotreater and an S-Zorb^TMunit. The refinery produces transportation fuels such as gasoline and diesel. Other products include residual fuel oil, which supplies the northwest marine transportation market. Most refined products are distributed by pipeline and barge to major markets in the northwest United States.

Los Angeles Refinery

The Los Angeles Refinery consists of two linked facilities located about five miles apart in Carson and Wilmington, California, approximately 15 miles southeast of Los Angeles International Airport. Carson serves as the front end of the refinery by processing crude oil, and Wilmington serves as the back end by upgrading the intermediate products to finished products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include fuel-grade petroleum coke. The refinery produces California Air Resources Board (CARB)-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. Refined products are distributed to customers in California, Nevada and Arizona by pipeline and truck.

San Francisco Refinery

The San Francisco Refinery consists of two facilities linked by a 200-mile pipeline. The Santa Maria facility is located in Arroyo Grande, California, about 200 miles south of San Francisco, California, while the Rodeo facility is in the San Francisco Bay Area. Semi-refined liquid products from the Santa Maria facility are sent by pipeline to the Rodeo facility for upgrading into finished petroleum products. The refinery produces a high percentage of transportation fuels, such as gasoline, diesel and jet fuel. Other products include petroleum coke. It also produces CARB-grade gasoline by blending ethanol to meet government-mandated oxygenate requirements. The majority of the refined products are distributed by pipeline, railcar and barge to customers in California.

Melaka Refinery

The Melaka Refinery in Melaka, Malaysia, is a joint venture refinery in which we own a 47 percent interest. Melaka produces a full range of refined petroleum products and capitalizes on coking technology to upgrade low-cost feedstocks into higher-margin products. Our share of refined products is transported by tanker and marketed in Malaysia and other Asian markets.

Marketing

Marketing—United States

In the United States, as of December 31, 2012, we marketed gasoline, diesel and aviation fuel through approximately 8,500 marketer-owned or -supplied outlets in 49 states. The majority of these sites utilize the Phillips 66, Conoco or 76 brands.

At December 31, 2012, our wholesale operations utilized a network of marketers operating approximately 7,100 outlets. We have placed a strong emphasis on the wholesale channel of trade because of its lower capital requirements. In addition, we held brand-licensing agreements with approximately 500 sites. Our refined products are marketed on both a branded and unbranded basis. A high percentage of our branded marketing sales are made in the Midcontinent, Rockies and West Coast regions, where our wholesale marketing operations provide efficient off-take from our refineries. The Gulf Coast and East Coast regions do not require a highly integrated marketing and distribution infrastructure to secure product placement for refinery pull-through. In these markets, most sales are conducted via unbranded sales. We are expanding our export capability at our U.S. coastal refineries to meet growing international demand and increase flexibility to provide product to the highest-value markets.

In addition to automotive gasoline and diesel, we produce and market jet fuel and aviation gasoline, which is used by smaller piston-engine aircraft. At December 31, 2012, aviation gasoline and jet fuel were sold through dealers and independent marketers at approximately 900 Phillips 66-branded locations in the United States.

Lubricants

We manufacture and sell automotive, commercial and industrial lubricants which are marketed worldwide under the Phillips 66, Conoco, 76 and Kendall brands, as well as other private label brands. We also manufacture Group II and import Group III base oils and market both globally under the respective brand names Pure Performance and Ultra-S.

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Index to Financial Statements

Premium Coke & Polypropylene

We manufacture and market high-quality graphite and anode-grade petroleum cokes in the United States and Europe for use in the global steel and aluminum industries. We also manufacture and market polypropylene to North America under the COPYLENE brand name.

Marketing—International

We have marketing operations in five European countries. Our European marketing strategy is to sell primarily through owned, leased or joint venture retail sites using a low-cost, high-volume approach. We use the JET brand name to market retail and wholesale products in Austria, Germany and the United Kingdom. In addition, a joint venture in which we have an equity interest markets products in Switzerland under the Coop brand name.

We also market aviation fuels, LPG, heating oils, transportation fuels, marine bunker fuels, bitumen and fuel coke specialty products to commercial customers and into the bulk or spot market in the above countries and Ireland.

As of December 31, 2012, we had approximately 1,425 marketing outlets in our European operations, of which approximately 915 were company owned and 310 were dealer owned. We also held brand-licensing agreements with approximately 200 sites. In addition, through our joint venture operations in Switzerland, we have interests in 250 additional sites.

Transportation

We own or lease various assets to provide environmentally safe, strategic and timely delivery of crude oil, refined products, natural gas and NGL. These assets include pipeline systems; petroleum product, crude oil and LPG terminals; a petroleum coke handling facility; a fleet of marine vessels; and a fleet of railcars.

Pipelines and Terminals

At December 31, 2012, our Transportation organization managed over 18,000 miles of crude oil, natural gas, NGL and petroleum products pipeline systems in the United States, including those partially owned or operated by affiliates and approximately 3,200 miles reported in our Midstream segment for the Rockies Express, Sand Hills and Southern Hills pipeline systems. We owned or operated 39 finished product terminals, 37 storage locations, 5 LPG terminals, 10 crude oil terminals and 1 petroleum coke exporting facility.

In June 2012, we sold the Trainer Refinery with associated terminal and pipeline assets, and in November 2012, we sold the Riverhead Terminal.

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Index to Financial Statements

The following table depicts our ownership interest in major R&M pipeline systems as of December 31, 2012:



Name	Origination/Terminus	Interest			Size	Miles	Capacity MBD
Crude
Coast and Valley System	Central CA/Bay Area, CA	100	%		8”-12”	702	307
Clifton Ridge	Clifton Ridge, LA/Westlake, LA	100			20”	10	270
Cushing (CushPo)	Cushing, OK/Ponca City, OK	100			18”	62	130
WA Line	Odessa, TX/Borger, TX	100			12”, 14”	300	118
Oklahoma Mainline/CPL	Wichita Falls, TX/Ponca City, OK	100			12”	217	100
Line O	Cushing, OK/Borger, TX	100			10”	276	37
Line 80 (Gaines Borger)	Gaines, TX/Borger, TX	100			8”, 12”	237	33
Glacier	Cut Bank, MT/Billings, MT	79			8”-12”	865	100

Petroleum Product
Sweeny to Pasadena	Sweeny, TX/Pasadena, TX	100			12”, 18”	120	264
Gold Line	Borger, TX/St. Louis, IL	100			8”-16”	681	120
Standish	Marland Junction, OK/Wichita, KS	100			18”	100	80
Borger to Amarillo	Borger, TX/Amarillo, TX	100			8”, 10”	93	76
Wood River	Ponca City, OK/Mt. Vernon, MO	100			10”, 12”	250	45
Okla. City/Cherokee 8”	Ponca City, OK/Okla. City, OK	100			8”	215	46
Wichita/Ark City 1&2	Ponca City, OK/Wichita, KS	100			8”, 10”	105	55
Seminoe	Billings, MT/Sinclair, WY	100			6”-10”	342	33
Borger-Denver	McKee, TX/Denver, CO	70			6”-12”	405	38
Pioneer	Sinclair, WY/Salt Lake City, UT	50			8”, 12”	562	63
ATA Line	Amarillo, TX/Albuquerque, NM	50			6”, 10”	293	20
Heartland	McPherson, KS/Des Moines, IA	50			8”, 6”	49	30
Yellowstone	Billings, MT/Spokane, WA	46			6”-10”	710	66
Harbor	Woodbury, NJ/Linden, NJ	33			16”	80	104
SAAL	Amarillo, TX/Amarillo and Lubbock, TX	33			6”	121	18
Explorer	Texas Gulf Coast/Chicago, IL	14			24”, 28”	1,835	500

NGL
Line EZ	Rankin, TX/Sweeny, TX	100		*	10”	434	101
Blue Line	Borger, TX/St. Louis, IL	100			8”-12”	666	29
Powder River	Douglas, WY/Borger, TX	100			6”-8”	695	19
Chisholm	Kingfisher, OK/Conway, KS	50			8”-10”	202	42
Skelly-Belvieu	Skellytown, TX/Mont Belvieu, TX	50			8”	571	29

LPG
Medford PBC	Ponca City, OK/Medford, OK	100			4”-12”	42	60
Conway to Wichita	Conway, KS/Wichita, KS	100			12”	55	38

*100% interest held by CPChem. Operated by Phillips 66.

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Tankers

At December 31, 2012, we utilized 12 double-hulled crude oil tankers that we chartered, with capacities ranging in size from 713,000 to 2,100,000 barrels. These tankers are primarily used to transport feedstocks to certain of our refineries. Additionally, in 2012, we entered into time charters on two Jones Act tankers to deliver shale crude to our Gulf Coast and East Coast refineries.

Truck and Rail

Truck and rail operations support our U.S. refinery and specialty operations. Rail movements are provided via a diverse fleet of more than 8,500 owned and leased railcars. In October 2012, we entered into an operating lease covering 2,000 new railcars under construction. We took delivery of the first 50 railcars in February 2013, and the remaining railcars are expected to be delivered in batches throughout 2013 and early 2014. This is an expansion of our existing rail business and will encompass delivery of advantaged crude to our refineries on the East and West Coasts. Truck movements are provided through approximately 150 third-party truck companies, as well as through Sentinel Transportation LLC, in which we hold an equity interest.

Specialty Businesses

We manufacture and sell a variety of specialty products including pipeline flow improvers and anode material for high-power lithium-ion batteries. Our specialty products are marketed under the LiquidPower and CPreme brand names.

Other

Immingham Combined Heat and Power Plant

The Immingham Combined Heat and Power Plant is a wholly owned 1,180-megawatt facility in the United Kingdom, which provides steam and electricity to the Humber Refinery and steam to a neighboring refinery, as well as merchant power into the U.K. market. The plant is capable of generating up to approximately 2.0 million pounds per hour of process steam.

Sweeny Cogeneration

We own a 50 percent operating interest in Sweeny Cogeneration, L.P., a joint venture which owns a simple-cycle cogeneration power plant located adjacent to the Sweeny Refinery. The plant generates electricity and provides process steam to the refinery, as well as merchant power into the Texas market. The plant has a net electrical output of 440 megawatts and is capable of generating up to 3.6 million pounds per hour of process steam.

MIDSTREAM

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGL from the raw gas stream. The remaining residue gas is marketed to electric utilities, industrial users and gas marketing companies. Most of the NGL is fractionated—separated into individual components such as ethane, propane and butane—and marketed as chemical feedstock, fuel or blendstock. Total NGL extracted in 2012, including our share of equity affiliates, was 201,000 barrels per day, compared with 192,000 barrels per day in 2011. The Midstream segment also includes an interstate natural gas transmission line.

DCP Midstream

Our Midstream segment includes our 50 percent equity investment in DCP Midstream, which is headquartered in Denver, Colorado. As of December 31, 2012, DCP Midstream owned or operated 62 natural gas processing facilities, with a net processing capacity of approximately 7.1 billion cubic feet per day. Its natural gas pipeline systems included gathering services for these facilities, as well as natural gas transmission, and totaled approximately 63,000 miles of pipeline. DCP Midstream also owned or operated 12 NGL fractionation plants, along with natural gas and NGL storage facilities, a propane wholesale marketing business and NGL pipeline assets.

In 2012, DCP Midstream gathered, processed and/or transported an average of 7.1 trillion British thermal units (TBTU) per day of natural gas, and produced approximately 402,000 barrels per day of NGL, compared with 7.0 TBTU per day and 383,000 barrels per day in 2011.

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The residual natural gas, primarily methane, which results from processing raw natural gas, is sold by DCP Midstream at market-based prices to marketers and end users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under the following types of contractual arrangements. More than 70 percent of the natural gas volumes gathered and processed are under percentage-of-proceeds contracts.

•

Percentage-of-proceeds/index arrangements. In general, DCP Midstream purchases natural gas from producers at the wellhead or other receipt points, gathers the wellhead natural gas through its gathering system, treats and processes it, and then sells the residue natural gas and NGL based on index prices from published market indices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received from the sale of the residue natural gas and NGL, or an agreed-upon percentage of the proceeds based on index-related prices for natural gas and NGL, regardless of the actual amount of sales proceeds which DCP Midstream receives. Certain of these arrangements may also result in DCP Midstream returning all or a portion of the residue natural gas and/or the NGL to the producer in lieu of returning sales proceeds. DCP Midstream's revenues from percentage-of-proceeds/index arrangements relate directly with the price of NGL and, to a lesser extent, natural gas and crude oil.

•

Fee-based arrangements. DCP Midstream receives a fee or fees for one or more of the following services: gathering, processing, compressing, treating, storing or transporting natural gas and fractionating, storing and transporting NGL. Fee-based arrangements include natural gas purchase arrangements pursuant to which DCP Midstream purchases natural gas at the wellhead or other receipt points at an index-related price at the delivery point less a specified amount, generally the same as the fees it would otherwise charge for gathering the natural gas from the wellhead location to the delivery point. The revenue DCP Midstream earns from these arrangements is directly related to the volume of natural gas or NGL that flows through its systems and is not directly dependent on commodity prices. However, to the extent that a sustained decline in commodity prices results in a decline in volumes, DCP Midstream's revenues from these arrangements could be reduced.

•

Keep-whole and wellhead purchase arrangements. DCP Midstream gathers raw natural gas from producers for processing, markets the NGL and returns to the producer residue natural gas with a British thermal unit (BTU) content equivalent to the BTU content of the natural gas gathered. This arrangement keeps the producer whole in regard to the thermal value of the natural gas received. Under the terms of a wellhead purchase contract, DCP Midstream purchases natural gas from the producer at the wellhead or defined receipt point for processing and markets the resulting NGL and residue gas at market prices. DCP Midstream is exposed to the difference between the value of the NGL extracted from processing and the value of the BTU-equivalent of the residue natural gas, or "frac spread." Under these type of contracts, DCP Midstream benefits in periods when NGL prices are higher relative to natural gas prices.

DCP Midstream markets a portion of its NGL to us and CPChem under an existing 15-year supply agreement, with a primary term ending December 31, 2014. Should the contract not be renegotiated or renewed, it provides for a five-year ratable wind-down period. This purchase commitment is on an “if-produced, will-purchase” basis and is expected to have a relatively stable purchase pattern over the remaining term of the contract. Under the agreement, NGL is purchased at various published market-index prices, less transportation and fractionation fees.

DCP Midstream is constructing a natural gas processing plant in the Eagle Ford shale area of Texas. The plant, named the Eagle Plant, is expected to have a capacity of 200 million cubic feet per day and be accompanied by related NGL infrastructure. The Eagle Plant is mechanically complete and is in the process of commencing operations, and will increase DCP Midstream's total natural gas processing capacity in the area to 1 billion cubic feet per day.

DCP Midstream is building two major NGL pipelines. The Sand Hills Pipeline will consist of approximately 720 miles of pipeline with initial capacity of 200,000 barrels per day, with expansion to 350,000 barrels per day possible. The Sand Hills Pipeline will provide NGL transportation from the Permian Basin and Eagle Ford region to the premium NGL markets on the Gulf Coast. In December 2012, the first phase of the Sand Hills Pipeline, which extends from Eagle Ford to Mont Belvieu, was placed in service. The second phase of the project, with deliveries from the Permian Basin, is expected to be completed in the second quarter of 2013.

The Southern Hills Pipeline will consist of more than 800 miles of NGL pipeline with initial capacity of approximately 150,000 barrels per day of Y-grade NGL, with expansion to 175,000 barrels per day expected. The Southern Hills Pipeline will be connected to several DCP Midstream processing plants and anticipated third-party producers, and will provide NGL transportation from the Midcontinent to Mont Belvieu, Texas. The Southern Hills Pipeline is expected to be in service in mid-2013.

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During the fourth quarter of 2012, Spectra Energy and Phillips 66 each acquired a one-third direct interest in both the Southern Hills and Sand Hills pipeline projects from DCP Midstream.

Rockies Express Pipeline LLC (REX)

We have a 25 percent interest in REX. The REX natural gas pipeline runs 1,679 miles from Cheyenne, Colorado, to Clarington, Ohio, and has a natural gas transmission capacity of 1.8 billion cubic feet per day, with most of its system having a pipeline diameter of 42 inches. Numerous compression facilities support the pipeline system. The REX pipeline is designed to enable natural gas producers in the Rocky Mountain region to deliver natural gas supplies to the Midwest and eastern regions of the United States.

Other Midstream

Outside of DCP Midstream and REX, our U.S. natural gas and NGL business includes the following:


•	A one-third direct interest in both the Sand Hills and Southern Hills pipeline projects, which currently are under construction by DCP Midstream.


•	A 22.5 percent equity interest in Gulf Coast Fractionators, which owns an NGL fractionation plant in Mont Belvieu, Texas. We operate the facility, and our net share of capacity is 32,625 barrels per day. In July 2012, the previously announced expansion of Gulf Coast Fractionators became operational and the total capacity of the fractionation facility expanded to 145,000 barrels per day.


•	A 40 percent interest in a fractionation plant in Conway, Kansas. Our net share of capacity is 43,200 barrels per day.


•	A 12.5 percent equity interest in a fractionation plant in Mont Belvieu, Texas. Our net share of capacity is 26,000 barrels per day.


•	Marketing operations that optimize the flow of NGL and market propane on a wholesale basis.

CHEMICALS

The Chemicals segment consists of our 50 percent equity investment in CPChem, which is headquartered in The Woodlands, Texas. At the end of 2012, CPChem owned or had joint-venture interests in 36 manufacturing facilities and 2 research and development centers around the world.

CPChem’s business is structured around two primary operating segments: Olefins and Polyolefins (O&P) and Specialties, Aromatics and Styrenics (SA&S). The O&P segment produces and markets ethylene, propylene, and other olefin products, which are primarily consumed within CPChem for the production of polyethylene, normal alpha olefins, polypropylene and polyethylene pipe. The SA&S segment manufactures and markets aromatics products, such as benzene, styrene, paraxylene and cyclohexane, as well as polystyrene and styrene-butadiene copolymers. SA&S also manufactures and/or markets a variety of specialty chemical products including organosulfur chemicals, solvents, catalysts, drilling chemicals, mining chemicals and high-performance engineering plastics and compounds.

The manufacturing of petrochemicals and plastics involves the conversion of hydrocarbon-based raw material feedstock into higher-value products, often through a thermal process referred to in the industry as “cracking.” For example, ethylene can be produced from cracking the feedstocks ethane, propane, butane, natural gasoline or certain refinery liquids, such as naphtha and gas oil. The produced ethylene has a number of uses, primarily as a raw material for the production of plastics, such as polyethylene and polyvinyl chloride (PVC). Plastic resins, such as polyethylene, are manufactured in a thermal/catalyst process, and the produced output is used as a further raw material for various applications, such as packaging and plastic pipe.

CPChem, including through its subsidiaries and equity affiliates, has manufacturing facilities located in Belgium, China, Colombia, Qatar, Saudi Arabia, Singapore, South Korea and the United States.

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The following table reflects CPChem’s petrochemicals and plastics product capacities at December 31, 2012:



	Millions of Pounds per Year
	U.S.	Worldwide
O&P
Ethylene	7,830	10,305
Propylene	2,975	3,480
High-density polyethylene	4,205	6,500
Low-density polyethylene	620	620
Linear low-density polyethylene	420	420
Polypropylene	—	310
Normal alpha olefins	1,490	2,005
Polyalphaolefins	105	235
Polyethylene pipe	590	590
Total O&P	18,235	24,465

SA&S
Benzene	1,600	2,530
Cyclohexane	1,060	1,455
Paraxylene	1,000	1,000
Styrene	1,050	1,875
Polystyrene	835	1,335
K-Resin^® SBC	100	170
Specialty chemicals	605	705
Ryton^® PPS	55	75
Total SA&S	6,305	9,145

Capacities include CPChem’s share in equity affiliates.

In December 2011, CPChem announced plans to pursue a project to construct a world-scale ethane cracker and two polyethylene facilities in the U.S. Gulf Coast region. The project would leverage the development of significant shale gas resources in the United States. CPChem's Cedar Bayou facility in Baytown, Texas, would be the location of the 3.3 billion-pound-per-year ethylene unit. In April 2012, CPChem announced that the two polyethylene facilities, each with an annual capacity of 1.1 billion pounds, would be located on a site near CPChem's Sweeny facility in Old Ocean, Texas. The final investment decision is expected in 2013.

In March 2012, CPChem announced plans to expand the NGL Fractionator Complex at its Sweeny facility in Old Ocean, Texas. The NGL fractionation expansion will increase its capacity by approximately 22,000 barrels per day, or a 19 percent increase over its current capacity. The project is expected to be completed in 2013.

In April 2012, CPChem announced plans to build a 1-hexene plant capable of producing up to 550 million pounds per year at its Cedar Bayou facility in Baytown, Texas. 1-hexene, a normal alpha olefin, is a critical component used in the manufacture of polyethylene, a plastic resin commonly converted into film, pipe, detergent bottles and food and beverage containers. Construction started in 2012, and the project is anticipated to start up during the first half of 2014.

Saudi Polymers Company (SPCo), a 35-percent-owned joint venture company of CPChem, owns and operates an integrated petrochemicals complex adjacent to S-Chem (two 50/50 SA&S joint ventures) at Jubail Industrial City, Saudi Arabia. SPCo produces ethylene, propylene, polyethylene, polypropylene, polystyrene and 1-hexene. SPCo announced commercial production in October 2012.

In association with the SPCo project, CPChem committed to build a nylon 6,6 manufacturing plant and a number of polymer conversion projects at Jubail Industrial City, Saudi Arabia. The projects are being undertaken through CPChem's 50 percent owned joint venture company Petrochemical Conversion Company Ltd. The projects are slated to begin operations in 2013.

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Our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if, at any time after the Separation, we experience a change in control or if both Standard & Poor's Ratings Services (S&P) and Moody's Investors Service (Moody's) lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks.

TECHNOLOGY DEVELOPMENT

Our Technology organization focuses in three areas: 1) advanced engineering optimization for our existing businesses, 2) sustainability technologies for a changing regulatory environment, and 3) future growth opportunities. Technology creates value through evaluation of advantaged crudes, models for increasing clean product yield, and through research to increase safety and reliability. Research allows Phillips 66 to be well positioned to address threats like corrosion, water consumption, and changing climate regulations. For example, we are progressing the technology development of second-generation biofuels both internally and with external collaborators.

COMPETITION

Our R&M segment competes primarily in the United States, Europe and Asia. Based on the statistics published in the December 3, 2012, issue of the Oil & Gas Journal, we are one of the largest refiners of petroleum products in the United States. Worldwide, our refining capacity ranked in the top 10 among non-government-controlled companies. In the Chemicals segment, CPChem generally ranked within the top 10 producers of many of its major product lines, based on average 2012 production capacity, as published by industry sources. Petroleum products, petrochemicals and plastics are typically delivered into the worldwide commodity markets. Elements of competition for both our R&M and Chemicals segments include product improvement, new product development, low-cost structures, and efficient manufacturing and distribution systems. In the marketing portion of the business, competitive factors include product properties and processibility, reliability of supply, customer service, price and credit terms, advertising and sales promotion, and development of customer loyalty to branded products.

The Midstream segment, through our equity investment in DCP Midstream and our other operations, competes with numerous integrated petroleum companies, as well as natural gas transmission and distribution companies, to deliver components of natural gas to end users in the commodity natural gas markets. DCP Midstream is one of the leading natural gas gatherers and processors in the United States based on wellhead volumes, and one of the largest U.S. producers and marketers of NGL, based on published industry sources. Principal methods of competing include economically securing the right to purchase raw natural gas for gathering systems, managing the pressure of those systems, operating efficient NGL processing plants and securing markets for the products produced.

GENERAL

At December 31, 2012, we held a total of 493 active patents in 46 countries worldwide, including 211 active U.S. patents. During 2012, we received 16 patents in the United States and 40 foreign patents. Our products and processes generated licensing revenues of $14 million in 2012. The overall profitability of any business segment is not dependent on any single patent, trademark, license or franchise.

Company-sponsored research and development activities charged against earnings were $76 million, $74 million and $56 million in 2012, 2011 and 2010, respectively.

In support of our goal to attain zero incidents, we have implemented a comprehensive Health, Safety and Environmental (HSE) management system to support our business units in achieving consistent management of HSE risks across our enterprise. The management system is designed to ensure that personal safety, process safety, and environmental impact risks are identified and mitigation steps are taken to reduce the risk. The management system requires periodic audits to ensure compliance with government regulations, as well as our internal requirements. Our commitment to continuous improvement is reflected in annual goal setting and performance measurement.

Please see the environmental information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contingencies” under the captions “Environmental” and “Climate

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Change.” It includes information on expensed and capitalized environmental costs for 2012 and those expected for 2013 and 2014.

Website Access to SEC Reports

Our Internet website address is http://www.phillips66.com. Information contained on our Internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the SEC. Alternatively, you may access these reports at the SEC's website at http://www.sec.gov.

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Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our operating results and our future rate of growth are exposed to the effects of changing commodity prices and refining and petrochemical margins.

Our revenues, operating results and future rate of growth are highly dependent on a number of factors, including fixed and variable expenses (including the cost of crude oil and other refinery feedstocks) and the margin relative to those expenses at which we are able to sell refined products. In recent years, the prices of crude oil and refined products have fluctuated substantially. These prices depend on numerous factors beyond our control, including the global supply and demand for crude oil, gasoline and other refined products, which are subject to, among other things:


•	Changes in the global economy and the level of foreign and domestic production of crude oil and refined products.


•	Availability of crude oil and refined products and the infrastructure to transport crude oil and refined products.


•	Local factors, including market conditions, the level of operations of other refineries in our markets, and the volume of refined products imported.


•	Threatened or actual terrorist incidents, acts of war and other global political conditions.


•	Government regulations.


•	Weather conditions, hurricanes or other natural disasters.

The price of crude oil influences prices for refined products. We do not produce crude oil and must purchase all of the crude oil we process. Many crude oils available on the world market will not meet the quality restrictions for use in our refineries. Others are not economical to use due to excessive transportation costs or for other reasons. The prices for crude oil and refined products can fluctuate differently based on global, regional and local market conditions. In addition, the timing of the relative movement of the prices (both among different classes of refined products and among various global markets for similar refined products), as well as the overall change in refined product prices, can reduce refining margins and could have a significant impact on our refining, wholesale marketing and retail operations, revenues, operating income and cash flows. Also, crude oil supply contracts generally have market-responsive pricing provisions. We normally purchase our refinery feedstocks weeks before manufacturing and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products produced by others for sale to our customers. Price level changes during the periods between purchasing and selling these refined products also could have a material adverse effect on our business, financial condition and results of operations.

Uncertainty and illiquidity in credit and capital markets can impair our ability to obtain credit and financing on acceptable terms and can adversely affect the financial strength of our business partners.

Our ability to obtain credit and capital depends in large measure on the state of the credit and capital markets, which is beyond our control. Our ability to access credit and capital markets may be restricted at a time when we would like, or need, access to those markets, which could constrain our flexibility to react to changing economic and business conditions. In addition, the cost and availability of debt and equity financing may be adversely impacted by unstable or illiquid market conditions. Protracted uncertainty and illiquidity in these markets also could have an adverse impact on our lenders, commodity hedging counterparties, or our customers, preventing them from meeting their obligations to us.

From time to time, our cash needs may exceed our internally generated cash flow, and our business could be materially and adversely affected if we are unable to obtain necessary funds from financing activities. From time to time, we may need to supplement our cash generated from operations with proceeds from financing activities. Uncertainty and illiquidity in financial markets may materially impact the ability of the participating financial institutions to fund their commitments to us under our liquidity facilities. Accordingly, we may not be able to obtain the full amount of the funds available under our liquidity facilities to satisfy our cash requirements, and our failure to do so could have a material adverse effect on our operations and financial position.

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Deterioration in our credit profile could increase our costs of borrowing money and limit our access to the capital markets and commercial credit, and could trigger co-venturer rights under joint venture arrangements.

Our credit ratings could be lowered or withdrawn entirely by a rating agency if, in its judgment, the circumstances warrant. If a rating agency were to downgrade our rating below investment grade, our borrowing costs would increase, and our funding sources could decrease. In addition, a failure by us to maintain an investment grade rating could affect our business relationships with suppliers and operating partners. For example, our agreement with Chevron regarding CPChem permits Chevron to buy our 50 percent interest in CPChem for fair market value if we experience a change in control or if both S&P and Moody's lower our credit ratings below investment grade and the credit rating from either rating agency remains below investment grade for 365 days thereafter, with fair market value determined by agreement or by nationally recognized investment banks. As a result of these factors, a downgrade of our credit ratings could have a materially adverse impact on our future operations and financial position.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

Our business is subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:


•	The discharge of pollutants into the environment.


•	Emissions into the atmosphere (such as nitrogen oxides, sulfur dioxide and mercury emissions, and greenhouse gas emissions as they are, or may become, regulated).


•	The handling, use, storage, transportation, disposal and clean up of hazardous materials and hazardous and nonhazardous wastes.


•	The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

To the extent there are significant changes in the Earth's climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and international governments through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and abroad. The U.S. government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments could limit our ability to operate in, or gain access to, opportunities in various countries, as well as limit our ability to obtain the optimum slate of crude oil and other refinery feedstocks. Our foreign operations and those of our joint ventures are further subject to risks of loss of revenue, equipment and property as a result of expropriation, acts of terrorism, war, civil unrest and other political risks; unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities; and difficulties enforcing rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Actions by both the United States and host governments may affect our operations significantly in the future.

Renewable fuels, alternative energy mandates and energy conservation efforts could reduce demand for refined products. Tax incentives and other subsidies can make renewable fuels and alternative energy more competitive with refined products than they otherwise might be, which may reduce refined product margins and hinder the ability of refined products to compete with renewable fuels.

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Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.

To approve a large-scale capital project, the project must meet an acceptable level of return on the capital to be employed in the project. We base these forecasted project economics on our best estimate of future market conditions. Most large-scale projects take many years to complete. During this multi-year period, market conditions can change from those we forecast, and these changes could be significant. Accordingly, we may not be able to realize our expected returns from a large investment in a capital project, and this could negatively impact our results of operations, cash flows and our return on capital employed.

Our investments in joint ventures decrease our ability to manage risk.

We conduct some of our operations, including a large part of our Midstream segment and our entire Chemicals segment, through joint ventures in which we share control with our joint venture participants. Our joint venture participants may have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture participants may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint-venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

Activities in our Chemicals and Midstream segments involve numerous risks that may result in accidents or otherwise affect the ability of our equity affiliates to make distributions to us.

There are a variety of hazards and operating risks inherent in the manufacture of petrochemicals and the gathering, processing, transmission, storage, and distribution of natural gas and NGL, such as spills, leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of human life, damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Should any of these risks materialize, it could have a material adverse effect on the business and financial condition of CPChem, DCP Midstream or REX and negatively impact their ability to make future distributions to us.

Our operations present hazards and risks, which may not be fully covered by insurance, if insured. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

The scope and nature of our operations present a variety of operational hazards and risks, including explosions, fires, toxic emissions, maritime hazards and natural catastrophes, that must be managed through continual oversight and control. For example, the operation of refineries, power plants, fractionators, pipelines and terminals is inherently subject to the risks of spills, discharges or other inadvertent releases of petroleum or hazardous substances. If any of these events had previously occurred or occurs in the future in connection with any of our refineries, pipelines or refined products terminals, or in connection with any facilities that receive our wastes or by-products for treatment or disposal, other than events for which we are indemnified, we could be liable for all costs and penalties associated with their remediation under federal, state, local and international environmental laws or common law, and could be liable for property damage to third-parties caused by contamination from releases and spills. These and other risks are present throughout our operations. As protection against these hazards and risks, we maintain insurance against many, but not all, potential losses or liabilities arising from such operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.

We often utilize the services of third parties to transport crude oil, NGL and refined products to and from our facilities. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessel to transport crude oil or refined product to or from one or more of our refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Increased regulation of hydraulic fracturing could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely impact our results of operations.

An increasing percentage of crude oil supplied to our refineries and the oil and gas production of DCP Midstream's customers is being developed from unconventional sources, such as deep oil and gas shales. These reservoirs require hydraulic fracturing completion processes to release the hydrocarbons from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate hydrocarbon production. The U.S. Environmental Protection Agency, as well as several state agencies, have commenced studies and/or convened hearings regarding the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and, if so, what its provisions would be. Any additional levels of regulation and permits required with the adoption of new laws and regulations at the federal or state level could result in our having to rely on higher priced crude oil for our refineries and lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through DCP Midstream's gathering systems. This could materially adversely affect our results of operations and the ability of DCP Midstream to make cash distributions to us.

Because of the natural decline in production from existing wells in DCP Midstream's areas of operation, its success depends on its ability to obtain new sources of natural gas and NGL. Any decrease in the volumes of natural gas DCP Midstream gathers could adversely affect its business and operating results.

DCP Midstream's gathering and transportation pipeline systems are connected to or dependent on the level of production from natural gas wells, from which production will naturally decline over time. As a result, its cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on its gathering and transportation pipeline systems and NGL pipelines and the asset utilization rates at its natural gas processing plants, DCP Midstream must continually obtain new supplies. The primary factors affecting DCP Midstream's ability to obtain new supplies of natural gas and NGL, and to attract new customers to its assets, include the level of successful drilling activity near these assets, the demand for natural gas and crude oil, producers' desire and ability to obtain necessary permits in an efficient manner, natural gas field characteristics and production performance, surface access and infrastructure issues, and its ability to compete for volumes from successful new wells. If DCP Midstream is not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells or because of competition, throughput on its pipelines and the utilization rates of its treating and processing facilities would decline. This could have a material adverse effect on its business, results of operations, financial position and cash flows, and its ability to make cash distributions to us.

Competitors that produce their own supply of feedstocks, have more extensive retail outlets, or have greater financial resources may have a competitive advantage.

The refining and marketing industry is highly competitive with respect to both feedstock supply and refined product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We do not produce any of our crude oil feedstocks. Some of our competitors, however, obtain a portion of their feedstocks from their own production and some have more extensive retail outlets than we have. Competitors that have their own production or extensive retail outlets (and greater brand-name recognition) are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our business. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers.

We may incur losses as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we utilize to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. If any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. The risk of counterparty default is heightened in a poor economic environment.

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A significant interruption in one or more of our facilities could adversely affect our business.

Our operations could be subject to significant interruption if one or more of our facilities were to experience a major accident or mechanical failure, power outage, encounter work stoppages relating to organized labor issues, be damaged by severe weather or other natural or man-made disaster, such as an act of terrorism, or otherwise be forced to shut down. If any facility were to experience an interruption in operations, earnings from the facility could be materially adversely affected (to the extent not recoverable through insurance, if insured) because of lost production and repair costs. A significant interruption in one or more of our facilities could also lead to increased volatility in prices for feedstocks and refined products, and could increase instability in the financial and insurance markets, making it more difficult for us to access capital and to obtain insurance coverage that we consider adequate.

Our performance depends on the uninterrupted operation of our facilities, which are becoming increasingly dependent on our information technology systems.

Our performance depends on the efficient and uninterrupted operation of the manufacturing equipment in our production facilities. The inability to operate one or more of our facilities due to a natural disaster; power outage; labor dispute; or failure of one or more of our information technology, telecommunications, or other systems could significantly impair our ability to manufacture our products. Our manufacturing equipment is becoming increasingly dependent on our information technology systems. A disruption in our information technology systems due to a catastrophic event or security breach could interrupt or damage our operations. In addition, we could be subject to reputational harm or liability if confidential customer information is misappropriated from our information technology systems. Despite our security measures and business continuity plans, these systems could be vulnerable to disruption, and any such disruption could negatively affect our financial condition and results of operations.

The level of returns on pension and postretirement plan assets and the actuarial assumptions used for valuation purposes could affect our earnings and cash flows in future periods.

Assumptions used in determining projected benefit obligations and the expected return on plan assets for our pension plan and other postretirement benefit plans are evaluated by us in consultation with outside actuaries. If we determine that changes are warranted in the assumptions used, such as the discount rate, expected long-term rate of return, or health care cost trend rate, our future pension and postretirement benefit expenses and funding requirements could increase. In addition, several factors could result in actual results differing significantly from the actuarial assumptions that we use. Funding obligations are determined based on the value of assets and liabilities on a specific date as required under relevant regulations. Future pension funding requirements, and the timing of funding payments, could be affected by legislation enacted by governmental authorities.

In connection with the Separation, ConocoPhillips has agreed to indemnify us for certain liabilities and we have agreed to indemnify ConocoPhillips for certain liabilities. If we are required to act on these indemnities to ConocoPhillips, we may need to divert cash to meet those obligations and our financial results could be negatively impacted. The ConocoPhillips indemnity may not be sufficient to insure us against the full amount of liabilities for which it has been allocated responsibility, and ConocoPhillips may not be able to satisfy its indemnification obligations in the future.

Pursuant to the Indemnification and Release Agreement and certain other agreements with ConocoPhillips entered into in connection with the Separation, ConocoPhillips agreed to indemnify us for certain liabilities, and we agreed to indemnify ConocoPhillips for certain liabilities. Indemnities that we may be required to provide ConocoPhillips are not subject to any cap, may be significant and could negatively impact our business, particularly indemnities relating to our actions that could impact the tax-free nature of the distribution of Phillips 66 stock. Third parties could also seek to hold us responsible for any of the liabilities that ConocoPhillips has agreed to retain. Further, the indemnity from ConocoPhillips may not be sufficient to protect us against the full amount of such liabilities, and ConocoPhillips may not be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from ConocoPhillips any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. Each of these risks could negatively affect our business, results of operations and financial condition.

We are subject to continuing contingent liabilities of ConocoPhillips following the Separation.

Notwithstanding the Separation, there are several significant areas where the liabilities of ConocoPhillips may become our obligations. For example, under the Internal Revenue Code and the related rules and regulations, each corporation that was a member of the ConocoPhillips consolidated U.S. federal income tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Separation is jointly and severally liable for the U.S. federal

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income tax liability of the entire ConocoPhillips consolidated tax reporting group for that taxable period. In connection with the Separation, we entered into the Tax Sharing Agreement with ConocoPhillips that allocates the responsibility for prior period taxes of the ConocoPhillips consolidated tax reporting group between us and ConocoPhillips. ConocoPhillips may be unable to pay any prior period taxes for which it is responsible, and we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.

If the distribution in connection with the Separation, together with certain related transactions, does not qualify as a transaction that is generally tax-free for U.S. federal income tax purposes, our stockholders and ConocoPhillips could be subject to significant tax liability and, in certain circumstances, we could be required to indemnify ConocoPhillips for material taxes pursuant to indemnification obligations under the Tax Sharing Agreement.

ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) substantially to the effect that, among other things, the distribution, together with certain related transactions, qualified as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The private letter ruling and the tax opinion that ConocoPhillips received relied on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the private letter ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the private letter ruling does not address all the issues that are relevant to determining whether the distribution qualified for tax-free treatment. Notwithstanding the private letter ruling and the tax opinion, the IRS could determine the distribution should be treated as a taxable transaction for U.S. federal income tax purposes if it determines any of the representations, assumptions or undertakings that were included in the request for the private letter ruling are false or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the IRS ruling.

If the IRS were to determine that the distribution failed to qualify for tax-free treatment, in general, ConocoPhillips would be subject to tax as if it had sold the Phillips 66 common stock in a taxable sale for its fair market value, and ConocoPhillips stockholders who received shares of Phillips 66 common stock in the distribution would be subject to tax as if they had received a taxable distribution equal to the fair market value of such shares.

Under the Tax Sharing Agreement, we would generally be required to indemnify ConocoPhillips against any tax resulting from the distribution to the extent that such tax resulted from (i) an acquisition of all or a portion of our stock or assets, whether by merger or otherwise, (ii) other actions or failures to act by us, or (iii) any of our representations or undertakings being incorrect or violated. Our indemnification obligations to ConocoPhillips and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify ConocoPhillips or such other persons under the circumstances set forth in the Tax Sharing Agreement, we may be subject to substantial liabilities.

We may not be able to engage in desirable strategic or capital-raising transactions due to limitations imposed on us as part of the Separation. In addition, under some circumstances, we could be liable for adverse tax consequences resulting from engaging in significant strategic or capital-raising transactions.

To preserve the tax-free treatment to ConocoPhillips of the distribution, for the two-year period following the distribution we may be prohibited, except in specified circumstances, from:


•	Entering into any transaction pursuant to which all or a portion of our stock would be acquired, whether by merger or otherwise.


•	Issuing equity securities beyond certain thresholds.


•	Repurchasing our common stock beyond certain thresholds.


•	Ceasing to actively conduct the refining business.


•	Taking or failing to take any other action that prevents the distribution and related transactions from being tax-free.

These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

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Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment, for this reporting period. It describes those matters previously reported in the Form 10 and in the Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2012, June 30, 2012, and September 30, 2012, that were not resolved prior to the fourth quarter of 2012. No new reportable matters arose during the fourth quarter of 2012 that were not previously reported. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were decided adversely to Phillips 66, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to SEC regulations.

Our U.S. refineries are implementing two separate consent decrees, regarding alleged violations of the Federal Clean Air Act, with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

New Matters

There were no new reportable matters that arose during the fourth quarter of 2012 that were not previously reported.

Matters Previously Reported

In October 2007, we received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Bayway Refinery and proposing a penalty of $156,000. We are working with the EPA and the U.S. Coast Guard to resolve this matter.

On May 19, 2010, the Lake Charles Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430. We are working with the LDEQ to resolve this matter.

In October 2011, we were notified by the Attorney General of the State of California that it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, we received notice of a lawsuit filed by the California Attorney General that alleges such violations. We are contesting these allegations.

On November 28, 2011, the Borger Refinery received a Notice of Enforcement from the Texas Commission on Environmental Quality (TCEQ) for alleged emissions events that occurred during inclement weather in January and February 2011. The TCEQ is seeking a penalty of $120,000. We are working with TCEQ to resolve this matter.

In December 2011, we were notified by the EPA of alleged violations related to the use of Renewable Identification Numbers (RINs). Phillips 66 was one of several companies that entered into Administrative Settlement Agreements (ASAs) with the EPA to settle allegations that it had used invalid RINs for its 2010 and 2011 fuel program compliance. Under the ASA, we will pay a maximum of $350,000 in penalties for the use of invalid RINs covered thereunder. Payments are made upon demand from the EPA. To date, $250,000 has been paid and it is anticipated that the EPA will demand the final $100,000 in 2013.

On March 7, 2012, the Bay Area Air Quality Management District (District) in California issued a $302,500 demand to settle five Notices of Violations (NOVs) issued between 2008 and 2010. The NOVs allege non-compliance with the District rules and/or facility permit conditions. We are working with the District to resolve this matter.

On September 19, 2012, the District issued a $213,500 demand to settle 14 NOVs issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the District to resolve this matter.

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On October 15, 2012, the District issued a $313,000 demand to settle 13 other NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Rodeo Refinery. We are working with the District to resolve this matter.

In May 2012, the Illinois Attorney General's office filed and notified us of a complaint with respect to operations at the WRB Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party's hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and yet-to-be specified amounts for fines and penalties. We are working with the Illinois Environmental Protection Agency and Attorney General's office to resolve these allegations.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

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EXECUTIVE OFFICERS OF THE REGISTRANT



Name	Position Held	Age*

Greg C. Garland	Chairman, President and Chief Executive Officer	55
C. Doug Johnson	Vice President and Controller	53
Paula A. Johnson	Senior Vice President, Legal, General Counsel and Corporate Secretary	49
Greg G. Maxwell	Executive Vice President, Finance and Chief Financial Officer	56
Tim G. Taylor	Executive Vice President, Commercial, Marketing, Transportation and Business Development	59
Lawrence M. Ziemba	Executive Vice President, Refining, Project Development and Procurement	57
*On February 15, 2013.

There are no family relationships among any of the officers named above. The Board of Directors annually elects the officers to serve until a successor is elected and qualified or as otherwise provided in our By-Laws. Set forth below is information about the executive officers identified above.

Greg C. Garland became Chairman of the Board of Directors, President and Chief Executive Officer of Phillips 66 on April 30, 2012. Mr. Garland was appointed Senior Vice President, Exploration and Production—Americas for ConocoPhillips in October 2010, having previously served as President and Chief Executive Officer of Chevron Phillips Chemical Company LLC (CPChem) since 2008. Prior to that, he served as Senior Vice President, Planning and Specialty Products at CPChem from 2000 to 2008. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

C. Doug Johnson became Vice President and Controller of Phillips 66 on April 30, 2012. Mr. Johnson served as General Manager, Upstream Finance, Strategy and Planning at ConocoPhillips since 2010. Prior to this, he served as General Manager, Downstream Finance from 2008 to 2010 and General Manager, Upstream Finance from 2005 to 2008.

Paula A. Johnson became Senior Vice President, Legal, General Counsel and Corporate Secretary of Phillips 66 on April 30, 2012. Ms. Johnson served as Deputy General Counsel, Corporate, and Chief Compliance Officer of ConocoPhillips since 2010. Prior to this, she served as Deputy General Counsel, Corporate from 2009 to 2010 and Managing Counsel, Litigation and Claims from 2006 to 2009.

Greg G. Maxwell became Executive Vice President, Finance and Chief Financial Officer of Phillips 66 on April 30, 2012. Mr. Maxwell retired as CPChem's Senior Vice President, Chief Financial Officer and Controller in 2012, a position held since 2003. He served as Vice President and Controller of CPChem from 2000 to 2003. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

Tim G. Taylor became Executive Vice President, Commercial, Marketing, Transportation and Business Development of Phillips 66 on April 30, 2012. Mr. Taylor retired as Chief Operating Officer of CPChem in 2011. Prior to this, Mr. Taylor served as Executive Vice President, Olefins and Polyolefins, at CPChem from 2008 to 2011, and Senior Vice President, Olefins and Polyolefins, from 2000 to 2008. Prior to joining CPChem in 2000, he held several senior positions with Phillips Petroleum Company.

Lawrence M. Ziemba became Executive Vice President, Refining, Project Development and Procurement, of Phillips 66 on April 30, 2012. Mr. Ziemba served as President, Global Refining, at ConocoPhillips since 2010. Prior to this, he served as President, U.S. Refining, from 2003 to 2010.

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PART II


Item 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

Phillips 66's common stock is traded on the New York Stock Exchange (NYSE) under the symbol “PSX.” The following table reflects intraday high and low sales prices of, and dividends declared on, our common stock for each quarter starting May 1, 2012, the date on which our stock began trading "regular-way" on the NYSE:



	Stock Price
	High		Low	Dividends
2012
Second Quarter	$	34.91	28.75	—
Third Quarter	48.22		32.35	.20
Fourth Quarter	54.32		42.45	.25

Issuer Purchases of Equity Securities



					Millions of Dollars
Period	Total Number of Shares Purchased*	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs**	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs

October 1-31, 2012	1,514,825	$	45.64	1,511,300	$	820
November 1-30, 2012	1,618,344	48.05		1,618,344	742
December 1-31, 2012	1,881,822	52.19		1,879,852	1,644
Total	5,014,991	$	48.87	5,009,496

*Includes repurchase of common shares from company employees in connection with the company's broad-based employee incentive plans.

**In July 2012, our Board of Directors authorized the repurchase of up to $1 billion of our outstanding common stock. We began purchases under this authorization, which has no expiration date, in the third quarter of 2012. In December 2012, an additional repurchase of up to $1 billion was approved by our Board of Directors, bringing the total program to $2 billion. The shares will be repurchased from time to time in the open market at the company’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Shares of stock repurchased are held as treasury shares.

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Item 6. SELECTED FINANCIAL DATA

Prior to the Separation, the following selected financial data consisted of the combined operations of the downstream businesses of ConocoPhillips. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly:

•

The selected income statement data for the year ended December 31, 2012, consists of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and of the combined results of the downstream businesses for the four months ended April 30, 2012. The selected income statement data for the years ended December 31, 2011, 2010, 2009 and 2008, consist entirely of the combined results of the downstream businesses.


•	The selected balance sheet data at December 31, 2012, consists of the consolidated balances of Phillips 66, while the selected balance sheet data at December 31, 2011, 2010, 2009 and 2008, consist of the combined balances of the downstream businesses.



	Millions of Dollars Except Per Share Amounts
	2012		2011	2010	2009	2008

Sales and other operating revenues	$	179,460	196,088	146,561	112,692	171,706
Net income	4,131		4,780	740	479	2,665
Net income attributable to Phillips 66	4,124		4,775	735	476	2,662
Per common share*
Basic	6.55		7.61	1.17	0.76	4.24
Diluted	6.48		7.52	1.16	0.75	4.19
Total assets	48,073		43,211	44,955	42,880	38,934
Long-term debt	6,961		361	388	403	417
Cash dividends declared per common share	0.45		—	—	—	—

*See Note 12—Earnings Per Share, in the Notes to Consolidated Financial Statements.

To ensure full understanding, you should read the selected financial data presented above in conjunction with “Management's Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and accompanying notes included elsewhere in this Annual Report on Form 10-K.

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the company’s analysis of its financial performance, financial condition, and significant trends that may affect future performance. It should be read in conjunction with the consolidated financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 52.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to Phillips 66.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

Phillips 66 is an international downstream company with refining and marketing, midstream and chemicals businesses. At December 31, 2012, we had total assets of $48 billion. Our common stock trades on the New York Stock Exchange under the symbol “PSX.”

We have organized our operations into three operating segments:


•	Refining and Marketing (R&M). This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. This segment also includes power generation activities, as well as specialties businesses such as flow improvers and lubricants.


•	Midstream. This segment gathers, processes, transports and markets natural gas; and transports, fractionates and markets natural gas liquids (NGL) in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream, LLC (DCP Midstream).


•	Chemicals. This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in Chevron Phillips Chemical Company LLC (CPChem).

The Separation

On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips shareholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. In conjunction with the Separation, ConocoPhillips received a private letter ruling from the Internal Revenue Service (IRS) to the effect that, based on certain facts, assumptions, representations and undertakings set forth in the ruling, for U.S. federal income tax purposes, the distribution of Phillips 66 stock was not taxable to ConocoPhillips or U.S. holders of ConocoPhillips common stock, except with respect to cash received in lieu of fractional share interests. Following the Separation, ConocoPhillips retained no ownership interest in Phillips 66, and each company now has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the Separation was filed by Phillips 66 with the U.S. Securities and Exchange Commission (SEC) and was declared effective on April 12, 2012 (the Form 10).

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Basis of Presentation

Prior to the Separation on April 30, 2012, our results of operations, financial position and cash flows consisted of ConocoPhillips' refining, marketing and transportation operations; its natural gas gathering, processing, transmission and marketing operations, including its equity investment in DCP Midstream; its petrochemical operations, conducted through its equity investment in CPChem; its power generation operations; and an allocable portion of its corporate costs (together, the “downstream businesses”). These financial statements have been presented as if the downstream businesses had been combined for all periods presented. All intercompany transactions and accounts within the downstream businesses were eliminated. The assets and liabilities have been reflected on a historical cost basis, as all of the assets and liabilities presented were wholly owned by ConocoPhillips and were transferred within the ConocoPhillips consolidated group. The statement of income for periods prior to the Separation includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. These allocations were based primarily on specific identification of time and/or activities associated with the downstream businesses, employee headcount or capital expenditures, and our management believes the assumptions underlying the allocations were reasonable. The combined financial statements may not necessarily reflect all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Separation. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66.

Executive Overview

We reported earnings of $4.1 billion in 2012. Refining margins remained strong in 2012, particularly in the Midcontinent region. Chemicals margins also remained robust in 2012. We generated cash from operations in 2012 of $4.3 billion, which we used to fund capital expenditures and investments of $1.7 billion, pay dividends of $282 million, repurchase $356 million of our common shares, make a $1.0 billion pre-payment on our debt, and increase our cash and cash equivalents balance to $3.5 billion at December 31, 2012. We ended 2012 with approximately $5.0 billion of total capacity under our available liquidity facilities.

Our solid financial results in 2012 allowed us to accelerate our strategy of creating value for shareholders:


•	We increased our quarterly dividend rate by 25 percent in the fourth quarter of 2012, to $0.25 per share. We also announced in the fourth quarter of 2012 that the annual dividend rate would be further increased by an additional 25 percent, effective in 2013.


•	We initiated a $1 billion share repurchase program in the third quarter of 2012 and, in the fourth quarter, we increased the program to $2 billion. Through December 31, 2012, we repurchased $356 million of our common shares.

We continue to focus on the following strategic areas:

•

Operating safely, reliably and in an environmentally sound manner. Safety and reliability are our first priority, and we are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. Optimizing utilization rates at our refineries through reliable and safe operations enables us to capture the value available in the market in terms of prices and margins. During 2012, our worldwide refining capacity utilization rate was 93 percent, compared with 92 percent in 2011. Additionally, we strive to conduct our operations in a manner consistent with our environmental stewardship principles.

•

Improving our advantaged crude runs in our refineries. U.S. crude production continued to increase and limited infrastructure for takeaway options resulted in lower feedstock costs for U.S. refiners with refineries that run advantaged crudes. Refineries capable of processing West Texas Intermediate (WTI) crude and crude oils that price relative to WTI, primarily the Midcontinent and Gulf Coast refineries, benefited from these lower regional feedstock prices. We are already running advantaged crude in eight of our refineries in the United States. We are moving advantaged crude by truck, rail, barge and ocean-going vessel to our refineries. We have expanded our truck, rail rack and marine capability, and we are leasing 2,000 additional railcars to deliver advantaged crude to our refineries.

•

Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, are high priorities. Operating and overhead costs increased 5 percent in 2012, compared with 2011, primarily due to the Separation. However, we have established “Optimize 66,” a program that concentrates on not only cost reductions, but also on process improvements, to improve our overall effectiveness and eliminate the cost “dis-synergies” resulting from the Separation.

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•

Funding growth and enhancing returns. Our capital program plan for 2013 is $3.7 billion, 3 percent higher than the 2012 program. This includes our portion of planned capital spending by DCP Midstream, CPChem and WRB Refining LP (WRB) totaling $1.8 billion, which is not expected to require cash outlays by us. The other $1.9 billion represents our consolidated investments in R&M, Midstream and Corporate and Other. This program is designed to grow our Midstream and Chemicals segments and to improve returns in our R&M segment. We intend to grow our Midstream segment both through our ownership in DCP Midstream and our own Phillips 66 midstream assets. We have invested directly in the Sand Hills and Southern Hills pipelines, and we have announced our plans to form a master limited partnership to grow additional midstream and transportation infrastructure in the future. We intend to grow our Chemicals segment through our ownership in CPChem. CPChem has large olefins and polyolefins projects underway in the U.S. Gulf Coast region. In the R&M segment, we plan to improve returns through increasing our advantaged crude runs in our refineries, while selectively investing in smaller, higher-return projects.

Business Environment

Results for our R&M segment depend largely on refining and marketing margins, cost control, refinery throughput, and product yields. The crack spread is a measure of the difference between market prices for refined petroleum products and crude oil, and it is used within our industry as an indicator for refining margins. Both domestic and international industry average crack spreads increased from 2010 to 2011 and again from 2011 to 2012. The improvements were consistent with improved global demand for refined products resulting from worldwide economic recovery along with limited net increases in global refining capacity. U.S. margins in the Midcontinent were especially strong, which can be attributed to the region's crude feedstock advantage.

In addition, U.S. crude production continued to increase, and limited infrastructure for takeaway options resulted in advantaged crude prices for U.S. refiners with access to advantaged crudes. Midcontinent refiners were especially advantaged. Increasing pressure on inventories in the Midcontinent continued to cause WTI crude to trade at a deep discount relative to crudes such as Light Louisiana Sweet (LLS) and Brent. Refineries capable of processing WTI crude and crude oils that price relative to WTI, primarily the Midcontinent and Gulf Coast refineries, benefited from these lower regional feedstock prices.

The Midstream segment's results are closely linked to NGL prices relative to crude oil prices and, to a lesser extent, natural gas prices. NGL prices improved in both 2010 and 2011 along with crude oil prices, but decreased in 2012 while crude prices stayed relatively stable. The NGL price decrease in 2012 was primarily due to growing NGL production from liquids-rich shale plays, while a corresponding demand increase from the petrochemical industry has not yet materialized as projects remain under development.

The Chemicals segment consists of our 50 percent equity investment in CPChem. The chemicals and plastics industry is mainly a commodity-based industry where the margins for key products are based on market factors. The chemicals and plastics industry experienced robust margin improvement from 2010 to 2011, and then again in 2012. Generally, ethylene margins improved in regions of the world where production is based upon NGL versus crude-derived feedstocks. In particular, North American ethane-based crackers benefited from the lower-priced feedstocks.

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RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s earnings by business segment follows:



	Millions of Dollars
	Year Ended December 31
	2012			2011		2010

R&M	$	3,729		3,848		146
Midstream	6			403		262
Chemicals	823			716		486
Corporate and Other	(434		)	(192	)	(159	)
Net income attributable to Phillips 66	$	4,124		4,775		735

2012 vs. 2011

Earnings for Phillips 66 decreased 14 percent in 2012, primarily resulting from:


•	A $1,437 million after-tax decrease in net gains on asset dispositions in 2012. 2011 results included significant gains on the disposition of three pipeline systems.


•	A $648 million after-tax increase in impairments in 2012, primarily reflecting 2012 impairments of our equity investments in Rockies Express Pipeline LLC (REX), a natural gas transmission system, and Malaysian Refining Company Sdn. Bdh. (MRC), a refining company in Melaka, Malaysia.


•	A $137 million after-tax increase in net interest expense, reflecting the issuance of $7.8 billion of debt during the first-half of 2012 in association with the Separation.


•	Lower NGL prices during 2012, which contributed to decreased earnings from our Midstream segment.

These items were partially offset by:


•	Improved refining margins in the R&M segment.


•	Improved ethylene and polyethylene margins in the Chemicals segment.

2011 vs. 2010

Earnings for Phillips 66 increased $4,040 million in 2011. The improved results in 2011 were primarily the result of:


•	Improved results from our R&M segment, reflecting significantly higher domestic refining margins.


•	Higher net gains from asset dispositions. 2011 net gains from asset dispositions were $1,546 million after tax, compared with 2010 gains of $118 million after tax.


•	Lower property impairments. 2010 earnings included a $1,174 million after-tax impairment of our formerly owned Wilhelmshaven Refinery (WRG) in Germany, which was partly offset by a $303 million after-tax impairment and warehouse inventory write-down associated with our Trainer Refinery in 2011.


•	Increased earnings in the Chemicals segment, primarily due to higher margins and volumes in the olefins and polyolefins business line.


•	Improved earnings from the Midstream segment, mainly due to higher NGL prices.

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Income Statement Analysis

2012 vs. 2011

Sales and other operating revenues decreased 8 percent in 2012, while purchased crude oil and products decreased 11 percent. The decreases were mainly due to processing lower refining volumes at our wholly owned refineries, resulting from the shutdown of Trainer Refinery in September 2011, combined with lower crude oil and NGL prices.

Equity in earnings of affiliates increased 10 percent in 2012, primarily resulting from improved earnings from WRB and CPChem. Equity in earnings of WRB increased 43 percent, mainly due to higher refining margins in the Central Corridor, combined with processing higher volumes associated with the startup of the coker and refining expansion (CORE) project at the Wood River Refinery. Equity in earnings of CPChem increased 22 percent, primarily resulting from higher ethylene and polyethylene margins. These improvements were partially offset by:


•	Lower earnings from DCP Midstream, mainly due to a decrease in NGL prices.


•	Lower earnings from Excel Paralubes, Merey Sweeny, L.P. (MSLP) and MRC, mainly due to lower margins.


•	The absence of earnings from Colonial Pipeline Company, which was sold in December 2011.

Net gain on dispositions decreased 88 percent in 2012, primarily resulting from 2011 gains associated with the disposition of three pipeline systems, compared with a net gain associated with the sale of Trainer Refinery and associated terminal and pipeline assets in the second quarter of 2012. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Other income increased $90 million in 2012, primarily associated with a keep-whole payment received from a third party associated with the sale of its ownership interest in REX, gains from trading activities not directly related to our physical business, and income received from ConocoPhillips associated with shared services.

Selling, general and administrative expenses increased 22 percent in 2012, primarily resulting from one-time and incremental costs associated with the Separation, as well as incremental costs relating to a prior retail disposition program.

Impairments in 2012 included our investments in MRC and REX, a marine terminal and associated assets, and equipment formerly associated with the canceled WRG upgrade project. Impairments in 2011 included the Trainer Refinery and associated terminal and pipeline assets. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Interest and debt expense increased $229 million in 2012, primarily due to approximately $7.8 billion of new debt issued in March and April of 2012. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rates.

2011 vs. 2010

Sales and other operating revenues increased 34 percent in 2011, while purchased crude oil and products increased 38 percent. These increases were primarily due to higher prices for petroleum products, crude oil and NGL.

Equity in earnings of affiliates increased 61 percent in 2011. The increase primarily resulted from:


•	Improved earnings from WRB, mainly due to higher refining margins.


•	Improved earnings from CPChem, primarily due to higher margins and volumes in the olefins and polyolefins business line and the startup of Q-Chem II at the end of 2010.


•	Improved earnings from DCP Midstream, primarily as a result of higher NGL prices.

Net gain on dispositions increased $1,397 million in 2011. Gains in 2011 primarily resulted from the disposition of three pipeline systems, partially offset by the loss on sale of WRG in 2011. Gains in 2010 mainly included the gain on sale of our 50 percent interest in CFJ Properties. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

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Impairments decreased 72 percent in 2011, primarily as a result of the $1,514 million impairment of WRG in 2010, partially offset by the $467 million Trainer Refinery impairment in 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Foreign currency transaction gains increased $119 million in 2011, as a result of the U.S. dollar weakening against the British pound and euro during 2011, compared with a strengthening in 2010.

See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

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Segment Results

R&M



	Year Ended December 31
	2012			2011	2010
	Millions of Dollars
Net Income (Loss) Attributable to Phillips 66
United States	$	3,730		3,637	1,013
International	(1		)	211	(867	)
	$	3,729		3,848	146

	Dollars Per Barrel
Refining Margins
Atlantic Basin/Europe	$	9.36		5.96	6.81
Gulf Coast	9.02			8.01	7.24
Central Corridor	25.06			19.68	7.96
Western/Pacific	11.04			9.13	8.10
Worldwide	13.42			9.70	7.38

	Dollars Per Gallon
U.S. Average Wholesale Prices*
Gasoline	$	3.00		2.94	2.24
Distillates	3.19			3.12	2.30
*Excludes excise taxes.

	Thousands of Barrels Daily
Operating Statistics
Refining operations*
Atlantic Basin/Europe
Crude oil capacity	588			726	1,033
Crude oil processed	555			682	686
Capacity utilization (percent)	94		%	94	66
Refinery production	599			736	746
Gulf Coast
Crude oil capacity	733			733	733
Crude oil processed	657			658	668
Capacity utilization (percent)	90		%	90	91
Refinery production	743			748	757
Central Corridor
Crude oil capacity	470			471	471
Crude oil processed	454			433	427
Capacity utilization (percent)	97		%	92	91
Refinery production	471			448	443
Western/Pacific
Crude oil capacity	439			435	420
Crude oil processed	398			393	375
Capacity utilization (percent)	91		%	91	89
Refinery production	419			419	395
Worldwide
Crude oil capacity	2,230			2,365	2,657
Crude oil processed	2,064			2,166	2,156
Capacity utilization (percent)	93		%	92	81
Refinery production	2,232			2,351	2,341
*Includes our share of equity affiliates.

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	Year Ended December 31
	2012	2011	2010
	Thousands of Barrels Daily
Petroleum products sales volumes
Gasoline	1,218	1,309	1,292
Distillates	1,141	1,219	1,189
Other products	502	600	559
	2,861	3,128	3,040

The R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. This segment also includes power generation operations. R&M has operations mainly in the United States, Europe and Asia.

2012 vs. 2011

R&M reported earnings of $3,729 million in 2012, a decrease of $119 million, or 3 percent, compared with 2011. See the “Business Environment and Executive Overview” section for information on industry crack spreads and other market factors impacting this year's results.

The decrease in earnings in 2012 was primarily due to lower net gains on disposition of assets, higher impairments and increased maintenance and repair expense associated with our Bayway Refinery as a result of severe weather disruptions. These items were partially offset by improved worldwide refining margins driven by improved market conditions and optimizing access to lower-cost crude oil feedstocks.

During 2012, R&M included an after-tax gain of $106 million from the sale of the Trainer Refinery and associated terminal and pipeline assets, compared with an after-tax gain of $1,595 million in 2011 on the sale of Seaway Products Pipeline Company and our ownership interest in Colonial Pipeline Company and Seaway Crude Pipeline Company. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Additionally, during 2012, R&M results included an after-tax impairment of $564 million on our equity investment in MRC, an after-tax impairment of $27 million on the Riverhead Terminal and a $42 million after-tax impairment related to equipment formerly associated with the canceled WRG upgrade project, compared with an after-tax impairment of $303 million on the Trainer Refinery during 2011. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

Our worldwide refining capacity utilization rate was 93 percent in 2012, compared with 92 percent in 2011. The current year improvement was primarily due to improved market conditions, partially offset by higher turnaround and maintenance activities, as well as severe weather disruptions.

2011 vs. 2010

R&M reported earnings of $3,848 million in 2011, an increase of $3,702 million compared with 2010. The increase in 2011 was primarily due to significantly higher U.S. refining margins, higher refining volumes, higher net gains from asset sales, foreign currency gains and the absence of the 2010 WRG impairment, partially offset by lower international refining margins and the $303 million after-tax impairment and warehouse inventory write-down associated with the idling of the Trainer Refinery in 2011.

In 2011, gains from asset sales of $1,627 million after tax mainly resulted from the sales of Seaway Products Pipeline Company, and our equity investments in Seaway Crude Pipeline Company and Colonial Pipeline Company. These gains were partially offset by the loss on the sale of WRG and related warehouse inventory write-downs. In 2010, gains from asset sales of $113 million after tax were mainly associated with the sale of our 50 percent interest in CFJ Properties.

Our worldwide refining capacity utilization rate was 92 percent in 2011, compared with 81 percent for 2010. The 2011 rate mainly reflected lower turnaround activity and the removal of WRG from our refining capacities effective January 1, 2011, partially offset by higher planned and unplanned downtime.

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Midstream



	Year Ended December 31
	2012		2011	2010
	Millions of Dollars

Net Income Attributable to Phillips 66*	$	6	403	262
*Includes DCP Midstream-related earnings:	$	179	287	210

	Dollars Per Barrel
Average Sales Prices
U.S. NGL*
Equity affiliates	$	34.24	50.64	41.28

*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by NGL component and location mix.



	Thousands of Barrels Daily
Operating Statistics
NGL extracted*	201	192	184
NGL fractionated**	105	112	120

*Includes our share of equity affiliates.

**Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract NGL from the raw gas stream. The remaining residue gas is marketed to electric utilities, industrial users and gas marketing companies. Most of the NGL are fractionated—separated into individual components such as ethane, propane and butane—and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, as well as other NGL fractionation, trading and marketing businesses in the United States. The Midstream segment also includes our 25 percent interest in REX and a one-third direct interest in both the Southern Hills and Sand Hills pipeline projects.

2012 vs. 2011

Earnings from the Midstream segment decreased $397 million in 2012, compared with 2011. The decrease was primarily due to impairments of our equity investment in REX during 2012 and decreased equity earnings from DCP Midstream, partially offset by a keep-whole payment received from a third party associated with the sale of its ownership interest in REX.

During 2012, we recorded after-tax impairments totaling $303 million on our equity investment in REX. The impairments primarily reflect a diminished view of fair value of west-to-east natural gas transmission, due to the impact of shale gas production in the northeast. For additional information, see Note 10—Impairments, in the Notes to Consolidated Financial Statements.

The decrease in earnings of DCP Midstream in 2012 mainly resulted from lower NGL prices and, to a lesser extent, lower natural gas prices, partially offset by lower depreciation and increased gain from the issuance of limited partner units by DCP Midstream Partners, L.P., as described below, and favorable volume impacts due to higher NGL extracted from liquid rich areas (such as Permian Basin, Eagle Ford Shale and Denver-Julesburg Basin). See the “Business Environment and Executive Overview” section for additional information on NGL prices.

During the second quarter of 2012, DCP Midstream completed a review of the estimated depreciable lives of its major classes of properties, plants and equipment. As a result of that review, the depreciable lives were extended. This change in accounting estimate was implemented on a prospective basis, effective April 1, 2012. DCP Midstream estimates its depreciation will be lowered approximately $240 million per year (on a 100 percent basis), which would be an estimated after-tax benefit to our equity in earnings from DCP Midstream of approximately $75 million.

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Index to Financial Statements

DCP Midstream Partners, L.P., a subsidiary of DCP Midstream, issues, from time to time, limited partner units to the public. These issuances benefited our equity in earnings from DCP Midstream by approximately $24 million after tax in 2012, compared with approximately $11 million after tax in 2011.

2011 vs. 2010

Midstream earnings increased 54 percent in 2011, compared with 2010. The increase was primarily due to higher equity earnings from DCP Midstream as a result of significantly higher NGL prices. Indexed NGL prices were 23 percent higher in 2011 than in 2010. Also benefiting 2011 earnings were higher fees received for NGL fractionation services, reflecting favorably renegotiated contracts. These items were partially offset by higher costs at DCP Midstream, primarily due to higher maintenance and repair costs and increased depreciation expense.

Chemicals



	Year Ended December 31
	2012		2011	2010
	Millions of Dollars

Net Income Attributable to Phillips 66	$	823	716	486

	Millions of Pounds
CPChem Externally Marketed Sales Volumes*
Olefins and polyolefins	14,967		14,305	12,585
Specialties, aromatics and styrenics	6,719		6,704	6,318
	21,686		21,009	18,903
*Represents 100 percent of CPChem's outside sales of produced petrochemical products, as well as commission sales from equity affiliates.

The Chemicals segment consists of our 50 percent interest in CPChem, which we account for under the equity method. CPChem uses NGL and other feedstocks to produce petrochemicals. These products are then marketed and sold or used as feedstocks to produce plastics and other chemicals.

2012 vs. 2011

Earnings from the Chemicals segment increased $107 million, or 15 percent, in 2012, compared with 2011. The increase was primarily driven by higher ethylene and polyethylene margins and lower utility costs, partially offset by a loss on early extinguishment of debt and fixed asset impairments. Ethylene margins benefited from lower feedstock costs, particularly lower ethane and propane prices during 2012. Utility costs benefited from lower natural gas prices during 2012.

During 2012, CPChem retired $1 billion of fixed-rate debt. CPChem also incurred prepayment premiums and wrote off the associated unamortized debt issuance costs. As a result, CPChem recognized a loss on early extinguishment of debt in 2012 of $287 million (100 percent basis), which decreased our equity in earnings from CPChem, on an after-tax basis, by approximately $90 million.

In addition, during 2012, CPChem recorded fixed asset impairments totaling $91 million (100 percent basis), which decreased our equity in earnings from CPChem, on an after-tax basis, by $28 million. These asset impairments primarily included certain specialties, aromatics and styrenics asset groups and were mainly driven by decreases in cash flow projections.

2011 vs. 2010

Chemicals segment earnings increased $230 million, or 47 percent, in 2011, compared with 2010. The improvement primarily resulted from higher margins, volumes and equity earnings from CPChem’s olefins and polyolefins business line. The specialties, aromatics and styrenics business line also contributed to the increase in earnings due to higher margins.

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Index to Financial Statements

Corporate and Other



	Millions of Dollars
	Year Ended December 31
	2012			2011		2010
Net Loss Attributable to Phillips 66
Net interest expense	$	(148	)	(11	)	—
Corporate general and administrative expenses	(116		)	(76	)	(71	)
Technology	(49		)	(53	)	(44	)
Repositioning costs	(55		)	—		—
Other	(66		)	(52	)	(44	)
	$	(434	)	(192	)	(159	)

2012 vs. 2011

Net interest expense consists of interest and financing expense, net of interest income and capitalized interest. Net interest expense increased $137 million in 2012, compared with 2011, primarily due to approximately $7.8 billion of new debt issued in March and April of 2012. For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

Corporate general and administrative expenses increased $40 million in 2012, compared with 2011. The increase was primarily due to incremental costs and expenses associated with operating as a stand-alone company for the eight months subsequent to the Separation.

Repositioning costs consist of expenses related to the Separation. Expenses incurred in the eight-month period subsequent to the Separation primarily included compensation and benefits, employee relocations and moves, information systems, and shared services costs.

Changes in the "Other" category were mainly due to an after-tax impairment of $16 million on a corporate property in 2012.

2011 vs. 2010

Net interest expense increased $11 million in 2011, primarily as a result of various tax-related adjustments in 2010. Technology’s net loss increased in 2011, mainly due to higher project expenses and lower licensing revenues. The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. Changes in the “Other” category were mainly due to higher environmental expenses associated with sites no longer in operation.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators



	Millions of Dollars Except as Indicated
	2012			2011	2010

Net cash provided by operating activities	$	4,296		5,006	2,092
Short-term debt	13			30	29
Total debt	6,974			391	417
Total equity	20,806			23,293	26,026
Percent of total debt to capital*	25		%	2	2
Percent of floating-rate debt to total debt	15		%	13	12
*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, but rely primarily on cash generated from operating activities. Proceeds from asset dispositions, funds from the issuance of debt, and, prior to April 30, 2012, proceeds from ConocoPhillips have also been sources of liquidity.

During 2012, we generated $4.3 billion in operating cash flows and received $7.8 billion in proceeds from the issuance of debt. During 2012, the primary uses of this available cash were $1.7 billion in capital expenditures and investments; $5.3 billion of distributions to ConocoPhillips as part of the Separation; $1.2 billion of debt repayment; $0.4 billion to repurchase common stock; and $0.3 billion to pay dividends on our common stock. We ended 2012 with cash and cash equivalents of $3.5 billion.

In addition to cash flows from operating activities and proceeds from asset sales, we rely on our credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. We believe current cash and cash equivalents and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending, dividend payments, defined benefit plan contributions, repayment of debt and share repurchases.

Significant Sources of Capital

Operating Activities

During 2012, cash of $4,296 million was provided by operating activities, a 14 percent decrease from cash from operations of $5,006 million in 2011. The decrease in the 2012 period primarily reflects the impact of working capital changes. Accounts payable activity lowered cash from operations by $985 million in 2012, primarily reflecting lower commodity prices and volumes. Inventory management had a reduced benefit to working capital in 2012, compared with 2011 (discussed in more detail below). Partially offsetting the negative impact of working capital changes in 2012 were:


•	Improved U.S. refining margins during 2012, reflecting improved market conditions and increasing access to lower-cost crude oil feedstocks.


•	Increased distributions from equity affiliates, particularly WRB, whose refineries are located in the Central Corridor region.

During 2011, cash of $5,006 million was provided by operating activities, a 139 percent increase from cash from operations of $2,092 million in 2010. The increase was primarily due to a significant improvement in U.S. refining margins in 2011, particularly in the Central Corridor region; increased distributions from equity affiliates, including CPChem, DCP Midstream and WRB; and inventory liquidations in 2011, compared with inventory builds in 2010.

Our short- and long-term operating cash flows are highly dependent upon refining and marketing margins, NGL prices, and chemicals margins. Prices and margins in our industry are typically volatile, and are driven by market conditions over which we have little or no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

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Generally, demand for gasoline is higher during the spring and summer months than during the fall and winter months in most of our markets due to seasonal changes in highway traffic. As a result, the R&M segment's operating results in the first and fourth quarters are generally lower than in the second and third quarters. However, our cash flow from operations may not always follow this seasonal trend in operating results, due to working capital fluctuations associated with inventory management. Historically, we have built inventory levels during the first quarter (thus lowering cash flow from operations) and lowered inventory levels in the fourth quarter (increasing cash flow from operations). In 2012, we used operating cash flows of $1.5 billion in the first quarter to build inventories, while the liquidation of inventories in the fourth quarter provided operating cash flows of $2.3 billion. For the full year 2012, inventory management had a lower benefit to cash from operations, compared with 2011, reflecting that a portion of our normal fourth-quarter inventory draw took place late in the year, such that cash realizations did not transpire prior to December 31.

The level and quality of output from our refineries also impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that caused by margins and prices. Our worldwide crude oil throughput capacity utilization was 93 percent in 2012, compared with 92 percent in 2011. We are forecasting 2013 utilization to remain in the low 90-percent range.

As part of our normal process, we made a scheduled U.S. federal income tax payment in the fourth quarter of 2012 using the IRS safe harbor method for estimated 2012 taxable income. We determined that a portion of that payment is refundable as an overpayment of estimated tax, and we intend to file for a "quick refund" with the IRS in the first quarter of 2013. We expect this refund to benefit cash from operations in the first quarter of 2013 by approximately $350 million.

Our operating cash flows are also impacted by distribution decisions made by our equity affiliates, including WRB, DCP Midstream and CPChem. Over the three years ended December 31, 2012, we received distributions of $1,932 million from WRB, $884 million from DCP Midstream and $1,380 million from CPChem. We cannot control the amount of future distributions from equity affiliates; therefore future distributions by these and other equity affiliates are not assured.

Asset Sales

Proceeds from asset sales in 2012 were $286 million, compared with $2,627 million in 2011 and $662 million in 2010. The 2012 proceeds from asset sales included the sale of our refinery and associated terminal and pipeline assets located in Trainer, Pennsylvania, as well as the sale of our Riverhead Terminal located in Riverhead, New York. The 2011 proceeds from asset sales included the sale of our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company, as well as the Wilhelmshaven Refinery and Seaway Products Pipeline Company. The 2010 proceeds included the sale of our 50 percent interest in CFJ Properties.

Credit Facilities

In February 2012, we entered into a five-year revolving credit agreement with a syndicate of financial institutions. Under the terms of the revolving credit agreement, we have a borrowing capacity of up to $4.0 billion. We have not borrowed under this facility. However, as of December 31, 2012, $51 million in letters of credit had been issued that were supported by this facility.

The revolving credit agreement contains covenants that we consider usual and customary for an agreement of this type for comparable commercial borrowers, including a maximum consolidated net debt-to-capitalization ratio of 60 percent. The agreement has customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control.

Borrowings under the credit agreement will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor's Ratings Services (S&P) and Moody's Investors Service (Moody's). The revolving credit agreement also provides for customary fees, including administrative agent fees and commitment fees.

During April 2012, a newly formed, wholly owned subsidiary entered into a trade receivables securitization facility. The facility has a term of three years and an aggregate capacity of $1.2 billion. As of December 31, 2012, we had not borrowed under the facility, but we had obtained $166 million in letters of credit under the facility that were collateralized by $166 million of the trade receivables held by the subsidiary.

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Debt Financings

During March 2012, we issued, through a private placement, $5.8 billion of debt consisting of:


•	$0.8 billion aggregate principal amount of 1.950% Senior Notes due 2015.


•	$1.5 billion aggregate principal amount of 2.950% Senior Notes due 2017.


•	$2.0 billion aggregate principal amount of 4.300% Senior Notes due 2022.


•	$1.5 billion aggregate principal amount of 5.875% Senior Notes due 2042.

The notes are guaranteed by Phillips 66 Company, a wholly owned subsidiary. In connection with the private placement, we and Phillips 66 Company entered into a Registration Rights Agreement with the initial purchasers of the notes pursuant to which we agreed, for the benefit of the holders of the notes, to use our commercially reasonable efforts to file with the SEC and cause to be effective a registration statement with respect to a registered offer to exchange each series of notes for new notes that are guaranteed by Phillips 66 Company with terms substantially identical in all material respects to such series of notes.

On November 5, 2012, we filed a registration statement on Form S-4 with the SEC in accordance with the Registration Rights Agreement outlining our offer to exchange our $5.8 billion senior notes for substantially identical notes without transfer restrictions. The registration statement was declared effective on November 15, 2012, and the exchange offer for the notes was completed in January 2013 with 99.9 percent participation.

During April 2012, approximately $185 million of previously existing debt was retired. Also during April, we closed on $2.0 billion of new debt in the form of a three-year amortizing term loan. The term loan bears interest at a variable rate based on referenced rates plus a margin dependent upon the credit rating of our senior unsecured long-term debt as determined from time to time by S&P and Moody's. As of December 31, 2012, the interest rate was 1.47 percent. In December 2012, we made a $1.0 billion pre-payment on the term loan.

Our senior unsecured long-term debt has been rated investment grade by S&P and Moody's. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating deteriorated to a level prohibiting us from accessing the commercial paper market, we would expect to be able to access funds under our $5.2 billion in liquidity facilities mentioned above.

Shelf Registration

We have a universal shelf registration statement on file with the SEC under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations, we enter into agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. In April 2012, in connection with the Separation, we entered into an agreement to guarantee 100 percent of certain outstanding debt obligations of MSLP. At December 31, 2012, the aggregate principal amount of MSLP debt guaranteed by us was $233 million.

For additional information about guarantees, see Note 14—Guarantees, in the Notes to Consolidated Financial Statements.

Capital Requirements

For information about our capital expenditures and investments, see “Capital Spending” below.

Our debt balance at December 31, 2012, was $7.0 billion and our debt-to-capital ratio was 25 percent, within our target range of 20-to-30 percent. In December 2012, we made a $1.0 billion pre-payment on our $2.0 billion term loan. As a result of this prepayment, we have no material scheduled debt maturities in 2013. However, we expect to repay the remaining $1.0 billion of the term loan before year-end 2013.

On February 10, 2013, our Board of Directors declared a quarterly cash dividend of $0.3125 per common share, payable March 1, 2013, to holders of record at the close of business on February 21, 2013. This represented a 25 percent increase over our fourth-quarter 2012 dividend rate of $0.25 per share and a 56 percent increase over our initial dividend rate after the Separation of $0.20 per share.

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On July 31, 2012, our Board of Directors authorized the repurchase of up to $1 billion of our outstanding common stock. On December 7, 2012, our Board authorized an additional $1 billion share repurchase, bringing the total repurchase program to $2 billion. We began purchases under this program, which has no expiration date, in the third quarter of 2012. The shares are repurchased in the open market at the company's discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Through December 31, 2012, $356 million was used to repurchase 7,603,896 shares. Shares of stock repurchased are held as treasury shares.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations as of December 31, 2012.



	Millions of Dollars
	Payments Due by Period
	Total		Up to 1 Year	Years 2-3	Years 4-5	After 5 Years

Debt obligations (a)	$	6,968	12	1,828	1,531	3,597
Capital lease obligations	6		1	2	3	—
Total debt	6,974		13	1,830	1,534	3,597
Interest on debt	4,044		258	490	421	2,875
Operating lease obligations	1,843		424	714	324	381
Purchase obligations (b)	133,571		46,796	20,232	13,921	52,622
Other long-term liabilities (c)
Asset retirement obligations	314		16	19	17	262
Accrued environmental costs	530		88	117	85	240
Unrecognized tax benefits (d)	10		10	(d)	(d)	(d)
Total	$	147,286	47,605	23,402	16,302	59,977


(a)	For additional information, see Note 13—Debt, in the Notes to Consolidated Financial Statements.

(b)

Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. We expect these purchase obligations will be fulfilled by operating cash flows in the applicable maturity period. The majority of the purchase obligations are market-based contracts, including exchanges and futures, for the purchase of products such as crude oil and unfractionated NGL. The products are mostly used to supply our refineries and fractionators, optimize the supply chain, and resell to customers. Product purchase commitments with third parties totaled $82,634 million. In addition, $40,478 million are product purchases from CPChem, mostly for natural gas and NGL over the remaining contractual term of 87 years, and $7,245 million from Excel Paralubes, for base oil over the remaining contractual term of 12 years.

Purchase obligations of $1,155 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and product terminals, to transport, process, treat, and store products. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned facilities where we are the operator.

(c)

Excludes pensions. For the 2013 through 2017 time period, we expect to contribute an average of $170 million per year to our qualified and nonqualified pension and other postretirement benefit plans in the United States and an average of $55 million per year to our non-U.S. plans, which are expected to be in excess of required minimums in many cases. The U.S. five-year average consists of $65 million for 2013 and then approximately $200 million per year for the remaining four years. Our minimum funding in 2013 is expected to be $65 million in the United States and $55 million outside the United States.


(d)	Excludes unrecognized tax benefits of $148 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable or the amounts relate to potential refunds. Also

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excludes interest and penalties of $15 million. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

Capital Spending



	Millions of Dollars
	2013 Budget		2012	2011	2010
Capital Expenditures and Investments
R&M
United States	$	1,034	833	751	798
International*	353		221	237	276
	1,387		1,054	988	1,074
Midstream**	361		527	17	68
Chemicals	—		—	—	—
Corporate and Other	161		140	17	8
Total consolidated	$	1,909	1,721	1,022	1,150

WRB	$	112	136	414	644
DCP Midstream**	1,100		1,324	779	411
CPChem	549		371	222	185
Selected equity affiliates***	$	1,761	1,831	1,415	1,240

*2013 budget amount includes non-cash capital lease of $152 million.

**2012 consolidated amount includes acquisition of a one-third interest in the Sand Hills and Southern Hills pipeline projects from DCP Midstream for

$459 million. This amount was also included in DCP Midstream's capital spending, primarily in 2012.

***Our share of capital spending which is self-funded by the equity affiliate.

R&M

Capital spending for the R&M segment during the three-year period ended December 31, 2012, was primarily for air emission reduction and clean fuels projects to meet new environmental standards, refinery upgrade projects to improve product yields and increase advantaged crude oil processing capability, improvements to the operating integrity of key processing units and safety-related projects. During this three-year period, R&M capital spending was $3.1 billion.

Key projects completed during the three-year period included:


•	Installation of facilities to reduce emissions from the fluid catalytic cracker at the Sweeny Refinery.


•	Installation of facilities to reduce nitrous oxide emissions from the crude furnace and installation of a new high-efficiency vacuum furnace at Bayway Refinery.


•	Completion of gasoline benzene reduction projects at the Alliance, Bayway, and Ponca City refineries.


•	Installation of new coke drums at the Billings Refinery.


•	Installation of a new carbon monoxide boiler at the Bayway Refinery to control carbon monoxide emissions while providing steam production.

Major construction activities in progress include:


•	Installation of facilities to reduce nitrous oxide emissions from the fluid catalytic cracker at the Alliance Refinery.


•	Installation of new coke drums at the Ponca City Refinery.


•	Installation of a tail gas treating unit at the Humber Refinery to reduce emissions from the sulfur recovery units.

Generally, our equity affiliates in the R&M segment are intended to have self-funding capital programs. Although WRB did not require capital infusions from us during the three-year period ended December 31, 2012, we did provide loan financing to WRB to assist it in meeting its operating and capital spending requirements. WRB repaid these loans in full during 2011. During this three-year period, on a 100 percent basis, WRB’s capital expenditures and investments were $2.4 billion. We expect WRB’s 2013 capital program to be self-funding.

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Midstream

During the three-year period ended December 31, 2012, DCP Midstream had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer, Spectra Energy Corp. During this three-year period, on a 100 percent basis, DCP Midstream’s capital expenditures and investments were $5.0 billion. In November 2012, we acquired a one-third direct interest in both the Sand Hills and Southern Hills pipeline projects, which currently are under construction and operated by DCP Midstream. Phillips 66, Spectra Energy and DCP Midstream now each own a one-third interest in the two pipeline projects. Our direct investment, in total, was $0.5 billion.

Other capital spending in our Midstream segment not related to DCP Midstream over the three-year period was primarily for investment in the construction of the Rockies Express pipeline, a natural gas transmission line running from Colorado to Ohio.

Chemicals

During the three-year period ended December 31, 2012, CPChem had a self-funded capital program, and thus required no new capital infusions from us or our co-venturer. During the three-year period, on a 100 percent basis, CPChem’s capital expenditures and investments were $1.6 billion. In addition, CPChem's advances to equity affiliates, primarily used for project construction and start-up activities, were $0.4 billion and its repayments received from equity affiliates were $0.3 billion. Our agreement with Chevron Corporation regarding CPChem provided for CPChem to: (i) prior to the Separation, halt all mandatory cash distributions to its owners and accumulate its excess cash; and (ii) after the Separation, use the accumulated cash and its excess cash flow to retire all of its approximately $1.0 billion outstanding fixed-rate debt on an accelerated basis. In the third quarter of 2012, CPChem completed the redemption of all outstanding fixed-rate debt, and it resumed cash distributions to its owners in the fourth quarter. After the Separation, the agreement generally provided that instead of CPChem incurring debt, CPChem's owners would make capital infusions as necessary to fund CPChem's capital requirements to the extent these requirements exceed CPChem's available cash from operations. We are currently forecasting CPChem to remain self-funding through 2013.

2013 Budget

Our 2013 planned capital budget is $1.9 billion. This excludes our portion of planned capital spending by DCP Midstream, CPChem and WRB totaling $1.8 billion, which is not expected to require cash outlays by us. Our 2013 budgeted consolidated capital expenditures and investments represent an 11 percent increase over our 2012 consolidated capital spending of $1.7 billion. R&M is expected to spend $1.4 billion in 2013, primarily directed toward reliability, maintenance, safety and environmental projects, as well as targeted growth and optimization spending. Approximately $1.0 billion of this amount is attributable to projects in the United States. The Midstream budget includes additional investment related to our one-third direct interest in the Sand Hills and Southern Hills pipelines. Within Corporate and Other, we expect to invest approximately $0.2 billion in 2013 related to information technology, facilities, and research and development.

Contingencies

A number of lawsuits involving a variety of claims have been made against us in connection with matters that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

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Legal and Tax Matters

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, are required. See Note 21—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:


•	U.S. Federal Clean Air Act, which governs air emissions.


•	U.S. Federal Clean Water Act, which governs discharges to water bodies.


•	European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).


•	U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.


•	U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.


•	U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories to local emergency planning committees and response departments.


•	U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.


•	U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.


•	European Union Trading Directive resulting in the European Emissions Trading Scheme.

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States.

An example in the fuels area is the Energy Policy Act of 2005, which imposed obligations to provide increasing volumes of renewable fuels in transportation motor fuels through 2012. These obligations were changed with the enactment of the Energy Independence and Security Act of 2007 (EISA). The 2007 law requires fuel producers and importers to provide additional renewable fuels for transportation motor fuels and stipulates a mix of various types to be included through 2022. We have met the increasingly stringent requirements to date while establishing implementation, operating and capital strategies, along with advanced technology development, to address projected future requirements. It is uncertain how various future requirements contained in EISA, and the regulations promulgated thereunder, may be implemented and what their full impact may be on our operations. Also, we may experience a decrease in demand for refined petroleum products due to the regulatory program as currently promulgated.

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We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Remediation obligations include cleanup responsibility arising from petroleum releases from underground storage tanks located at numerous past and present owned and/or operated petroleum-marketing outlets throughout the United States. Federal and state laws require contamination caused by such underground storage tank releases be assessed and remediated to meet applicable standards. In addition to other cleanup standards, many states have adopted cleanup criteria for methyl tertiary-butyl ether (MTBE) for both soil and groundwater.

At RCRA-permitted facilities, we are required to assess environmental conditions. If conditions warrant, we may be required to remediate contamination caused by prior operations. In contrast to CERCLA, which is often referred to as “Superfund,” the cost of corrective action activities under RCRA corrective action programs typically is borne solely by us. We anticipate increased expenditures for RCRA remediation activities may be required, but such annual expenditures for the near term are not expected to vary significantly from the range of such expenditures we have experienced over the past few years. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

We occasionally receive requests for information or notices of potential liability from the U.S. Environmental Protection Agency (EPA) and state environmental agencies alleging we are a potentially responsible party under CERCLA or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain wastes attributable to our past operations. As of December 31, 2011, we reported we had been notified of potential liability under CERCLA and comparable state laws at 61 sites around the United States. At December 31, 2012, we had been notified of 1 new site, settled 3 sites and 11 sites were resolved and closed, leaving 48 sites with potential liability.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval of a remediation plan. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $645 million in 2012 and are expected to be approximately $650 million per year in 2013 and 2014. Capitalized environmental costs were $264 million in 2012 and are expected to be approximately $320 million per year in 2013 and 2014. This amount does not include capital expenditures made for another purpose that have an indirect benefit on environmental compliance.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted, operations or at sites where our generated waste was disposed. We also have accrued for a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or state enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA. Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2012, our balance sheet included total accrued environmental costs of $530 million, compared with $542 million at December 31, 2011, and $554 million at December 31, 2010. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities

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will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

The EPA’s Renewable Fuel Standard (RFS) program was implemented in accordance with the Energy Policy Act of 2005 and the EISA. The RFS program sets annual quotas for the percentage of biofuels (such as ethanol) that must be blended into motor fuels consumed in the United States. A Renewable Identification Number (RIN) represents a serial number assigned to each gallon of biofuel produced or imported into the United States. As a producer of petroleum-based motor fuels, we are obligated to blend biofuels into the products we produce at a rate that is at least equal to the EPA’s quota and, to the extent we do not, we must purchase RINs in the open market to satisfy our obligation under the RFS program. The market for RINs has been the subject of fraudulent activity, and we have identified that we have unknowingly purchased RINs in the past that were invalid due to fraudulent activity. Although costs to replace fraudulently marketed RINs that have been determined to be invalid have not been material through December 31, 2012, it is reasonably possible that some additional RINs that we have previously purchased may also be determined to be invalid. Should that occur, we could incur additional replacement charges. Although the cost for replacing any additional fraudulently marketed RINs is not reasonably estimable at this time, we could have a possible exposure of approximately $150 million before tax. It could take several years for this possible exposure to reach ultimate resolution; therefore, we would not expect to incur the full financial impact of additional fraudulent RIN replacement costs in any single interim or annual period.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation or precursors for possible regulation that do or could affect our operations include:


•	European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol.


•	California’s Global Warming Solutions Act, which requires the California Air Resources Board to develop regulations and market mechanisms that will target reduction of California’s GHG emissions by 25 percent by 2020.


•	The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

•

The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under the Clean Air Act. These collectively may lead to more climate-based claims for damages, and may result in longer agency review time for development projects to determine the extent of potential climate change. Challenges to both the announcement and rulemaking were denied by the Court of Appeals for the D.C. Circuit (see Coalition for Responsible Regulation v. EPA, 684 F. 3d 102 (D.C. Cir. 2012)), but may be subject to additional legal actions.


•	Carbon taxes in certain jurisdictions.


•	GHG emission cap and trade programs in certain jurisdictions.

In the EU, we have assets that are subject to the ETS. The first phase of the ETS was completed at the end of 2007 and Phase II ran from 2008 through 2012. Phase III will run from 2013 through 2020 and there will likely be a significant increase in auctioning levels, including 100 percent auctioning to the power sector in the UK and across most of the EU. We are actively engaged to minimize any financial impact from the trading scheme.

In the United States, some additional form of regulation may be forthcoming in the future at the federal or state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.

Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources. An example of one such program is California's cap and trade program, which was promulgated pursuant to the State's Global Warming Solutions Act. The program currently is limited to certain stationary sources, which include our refineries in

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California, but beginning in 2015 will expand to include emissions from transportation fuels distributed in California. We expect inclusion of transportation fuels in California's cap and trade program as currently promulgated would increase our cap and trade program compliance costs. The ultimate impact on our financial performance, either positive or negative, from this and similar programs, will depend on a number of factors, including but not limited to:


•	Whether and to what extent legislation is enacted.


•	The nature of the legislation (such as a cap and trade system or a tax on emissions).


•	The GHG reductions required.


•	The price and availability of offsets.


•	The amount and allocation of allowances.


•	Technological and scientific developments leading to new products or services.


•	Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).


•	Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 2—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, along with the discussion of contingencies in this report, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally at an entire refinery complex level. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future volumes, commodity prices, operating costs, margins, discount rates and capital project decisions, considering all available information at the date of review.

Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

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Asset Retirement Obligations

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land at the end of operations at certain operational sites. Our largest asset removal obligations involve asbestos abatement at refineries. Estimating the future asset removal costs necessary for this accounting calculation is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

Environmental Costs

In addition to asset retirement obligations discussed above, under the above or similar contracts, permits and regulations, we have certain obligations to complete environmental-related projects. These projects are primarily related to cleanup at domestic refineries, underground storage sites and non-operated sites. Future environmental remediation costs are difficult to estimate because they are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties.

Intangible Assets and Goodwill

At December 31, 2012, we had $701 million of intangible assets determined to have indefinite useful lives, and thus they are not amortized. This judgmental assessment of an indefinite useful life must be continuously evaluated in the future. If, due to changes in facts and circumstances, management determines these intangible assets have finite useful lives, amortization will commence at that time on a prospective basis. As long as these intangible assets are judged to have indefinite lives, they will be subject to annual lower-of-cost-or-fair value tests that require management’s judgment of the estimated fair value of these intangible assets.

At December 31, 2012, we had $3.3 billion of goodwill recorded in conjunction with past business combinations. Under the accounting rules for goodwill, this intangible asset is not amortized. Instead, goodwill is subject to at least annual reviews for impairment at a reporting unit level. The reporting unit or units used to evaluate and measure goodwill for impairment are determined primarily from the manner in which the business is managed. A reporting unit is an operating segment or a component that is one level below an operating segment. We determined we had one reporting unit for purposes of assigning goodwill and testing for impairment—the R&M operating segment. We have concluded the refining and marketing components within the R&M segment are economically similar enough to be aggregated into one reporting unit.

If we later reorganize our businesses or management structure so that our operating segments change, or such that the components within our reporting unit are no longer economically similar, the reporting units would be revised and goodwill would be reassigned using a relative fair value approach. Goodwill impairment testing at a lower reporting unit level could result in the recognition of impairment that would not otherwise be recognized at the current level. In addition, the sale or disposition of a portion of our reporting unit will be allocated a portion of the reporting unit’s goodwill, based on relative fair values, which will adjust the amount of gain or loss on the sale or disposition.

Because quoted market prices for our reporting unit are not available, management must apply judgment in determining the estimated fair value of this reporting unit for purposes of performing the goodwill impairment test. Management uses all available information to make this fair value determination, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets and observed market multiples of operating cash flows and net income. In addition, if the estimated fair value of the reporting unit is less than the book value (including the goodwill), further management judgment must be applied in determining the fair values of individual assets and liabilities for purposes of the hypothetical purchase price allocation. At year-end 2012, the estimated fair value of our R&M operating segment (reporting unit) was approximately 30 percent higher than recorded net book values (including goodwill) of the reporting unit. However, a lower fair value estimate in the future could result in an impairment. Our common stock price and associated total company market capitalization are also considered in the determination of reporting unit fair value. A prolonged or significant decline in our stock price could provide evidence of a need to record a material impairment of goodwill.

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Tax Assets and Liabilities

Our operations are subject to various taxes, including federal, state and foreign income taxes and transactional taxes such as excise, sales/use, property and payroll taxes. We record tax liabilities based on our assessment of existing tax laws and regulations. The recording of tax liabilities may require significant judgment and estimates. We recognize the financial statement effects of an income tax position when it is more likely than not that the position will be sustained upon examination by a taxing authority. A contingent liability related to a transactional tax claim is recorded if the loss is both probable and estimable. Actual incurred tax liabilities can vary from our estimates for a variety of reasons, including different interpretations of tax laws and regulations and different assessments of the amount of tax due.

In determining our income tax provision, we must assess the likelihood our deferred tax assets will be recovered through future taxable income. Valuation allowances reduce deferred tax assets to an amount that will, more likely than not, be realized. Judgment is required in estimating the amount of valuation allowance, if any, that should be recorded against our deferred tax assets. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, we expect the net deferred tax assets will more likely than not be realized as offsets to reversing deferred tax liabilities and as reductions to future taxable income. If our actual results of operations differ from such estimates or our estimates of future taxable income change, the valuation allowance may need to be revised.

New tax laws and regulations, as well as changes to existing tax laws and regulations, are continuously being proposed or promulgated. The implementation of future legislative and regulatory tax initiatives could result in increased tax liabilities that cannot be predicted at this time.

Projected Benefit Obligations

Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by an estimated $60 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by an estimated $20 million. In determining the discount rate, we use yields on high-quality fixed income investments with payments matched to the estimated distributions of benefits from our plans.

OUTLOOK

In December 2012, we announced our intention to contribute a portion of our transportation and logistics assets to form a master limited partnership (MLP). We are evaluating assets for contribution to the MLP, including certain petroleum product and crude oil pipelines and terminals. A registration statement for an initial public offering (IPO) is expected to be filed with the SEC in the second quarter of 2013. Subject to market conditions and final approval by our Board of Directors, we anticipate selling a minority interest in the MLP in an IPO in the second half of 2013.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial- and commodity-based derivative contracts to manage the risks produced by changes in the prices of crude oil and related products, natural gas and electric power; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient market liquidity for comparable valuations. The Authority Limitations document also establishes the Value at Risk (VaR) limits for us, and compliance with these limits is monitored daily. Our Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates. Our Executive Vice President over the Commercial organization monitors commodity price risk. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors related risks of our businesses.

Commodity Price Risk

We sell into or receive supply from the worldwide crude oil, refined products, natural gas, NGL, and electric power markets and are exposed to fluctuations in the prices for these commodities.

These fluctuations can affect our revenues and purchases, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities.

Our Commercial organization uses futures, forwards, swaps and options in various markets to optimize the value of our supply chain, which may move our risk profile away from market average prices to accomplish the following objectives:


•	Balance physical systems. In addition to cash settlement prior to contract expiration, exchange-traded futures contracts also may be settled by physical delivery of the commodity, providing another source of supply to meet our refinery requirements or marketing demand.


•	Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by refined product consumers, to a floating-market price.


•	Manage the risk to our cash flows from price exposures on specific crude oil, refined product, natural gas, and electric power transactions.


•	Enable us to use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be utilized to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments held or issued, including commodity purchase and sales contracts recorded on the balance sheet at December 31, 2012, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2012 and 2011, was immaterial to our cash flows and net income.

The VaR for instruments held for purposes other than trading at December 31, 2012 and 2011, was also immaterial to our cash flows and net income.

Interest Rate Risk

The following table provides information about our debt instruments that are sensitive to changes in U.S. interest rates. The table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices.

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	Millions of Dollars Except as Indicated
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate		Floating Rate Maturity		Average Interest Rate
Year-End 2012
2013	$	12	7.00	%	$	—	—	%
2014		14	7.00			286	1.47
2015		814	2.04			714	1.47
2016		15	7.00			—	—
2017		1,516	2.99			—	—
Remaining years		3,552	5.00			50	0.24
Total	$	5,923			$	1,050
Fair value	$	6,507			$	1,050

For additional information about our use of derivative instruments, see Note 16—Derivatives and Financial Instruments, in the Notes to Consolidated Financial Statements.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:


•	Fluctuations in crude oil, NGL, and natural gas prices, refining and marketing margins and margins for our chemicals business.


•	Failure of new products and services to achieve market acceptance.


•	Unexpected changes in costs or technical requirements for constructing, modifying or operating facilities for manufacturing, refining or transportation projects.


•	Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.


•	Lack of, or disruptions in, adequate and reliable transportation for our crude oil, natural gas, NGL and refined products.


•	The level and success of natural gas drilling around DCP Midstream’s assets, the level and quality of gas production volumes around its assets and its ability to connect supplies to its gathering and processing systems in light of competition.


•	Inability to timely obtain or maintain permits, including those necessary for capital projects; comply with government regulations; or make capital expenditures required to maintain compliance.


•	Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future refinery, chemical plant, midstream and transportation projects.


•	Potential disruption or interruption of our operations due to accidents, weather events, civil unrest, political events, terrorism or cyber attacks.


•	International monetary conditions and exchange controls.


•	Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.


•	Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.


•	Liability resulting from litigation.


•	General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, natural gas, NGL or refined product pricing, regulation or taxation; other political, economic or diplomatic developments; and international monetary fluctuations.


•	Changes in tax, environmental and other laws and regulations (including alternative energy mandates) applicable to our business.


•	Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.


•	Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.


•	The operation, financing and distribution decisions of our joint ventures.


•	Domestic and foreign supplies of crude oil and other feedstocks.


•	Domestic and foreign supplies of refined products, such as gasoline, diesel, jet fuel, home heating oil and petrochemicals.


•	Overcapacity or under capacity in the refining, midstream and chemical industries.


•	Fluctuations in consumer demand for refined products.

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•	Crude oil/refined product inventory levels.


•	The factors generally described in Item 1A—Risk Factors in this report.

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PHILLIPS 66

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Management	55
Report of Independent Registered Public Accounting Firm	56

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	57

Consolidated Financial Statements of Phillips 66:

Consolidated Statement of Income for the years ended December 31, 2012, 2011 and 2010	58

Consolidated Statement of Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	59

Consolidated Balance Sheet at December 31, 2012 and 2011	60

Consolidated Statement of Cash Flows for the years ended December 31, 2012, 2011 and 2010	61

Consolidated Statement of Changes in Equity for the years ended December 31, 2012, 2011 and 2010	62

Notes to Consolidated Financial Statements	63

Supplementary Information

Selected Quarterly Financial Data (Unaudited)	112

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Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company's financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company's financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors. Management has made available to Ernst & Young LLP all of the company's financial records and related data, as well as the minutes of stockholders' and directors' meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. Phillips 66's internal control system was designed to provide reasonable assurance to the company's management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2012. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework. Based on our assessment, we believe the company's internal control over financial reporting was effective as of December 31, 2012.

Ernst & Young LLP has issued an audit report on the company's internal control over financial reporting as of December 31, 2012, and their report is included herein.




/s/ Greg C. Garland		/s/ Greg G. Maxwell

Greg C. Garland		Greg G. Maxwell
Chairman, President and		Executive Vice President, Finance
Chief Executive Officer		and Chief Financial Officer



February 22, 2013

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Phillips 66

We have audited the accompanying consolidated balance sheet of Phillips 66 as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the financial statement schedule included in Item 15(a)2. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Phillips 66 at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Phillips 66's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2013

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Report of Independent Registered Public Accounting Firm on

Internal Control Over Financial Reporting

The Board of Directors and Stockholders

Phillips 66

We have audited Phillips 66's internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Phillips 66's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Phillips 66 maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2012 consolidated financial statements of Phillips 66 and our report dated February 22, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 22, 2013

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Index to Financial Statements



Consolidated Statement of Income	Phillips 66
	Millions of Dollars
Years Ended December 31	2012			2011		2010
Revenues and Other Income
Sales and other operating revenues*	$	179,460		196,088		146,561
Equity in earnings of affiliates	3,134			2,843		1,765
Net gain on dispositions	193			1,638		241
Other income	135			45		89
Total Revenues and Other Income	182,922			200,614		148,656

Costs and Expenses
Purchased crude oil and products	154,483			172,837		125,092
Operating expenses	4,032			4,072		4,189
Selling, general and administrative expenses	1,722			1,409		1,384
Depreciation and amortization	913			908		880
Impairments	1,158			472		1,699
Taxes other than income taxes*	13,741			14,288		13,985
Accretion on discounted liabilities	25			21		22
Interest and debt expense	246			17		1
Foreign currency transaction (gains) losses	(29		)	(34	)	85
Total Costs and Expenses	176,291			193,990		147,337
Income before income taxes	6,631			6,624		1,319
Provision for income taxes	2,500			1,844		579
Net income	4,131			4,780		740
Less: net income attributable to noncontrolling interests	7			5		5
Net Income Attributable to Phillips 66	$	4,124		4,775		735

Net Income Attributable to Phillips 66 Per Share of Common Stock (dollars)**
Basic	$	6.55		7.61		1.17
Diluted	6.48			7.52		1.16

Dividends Paid Per Share of Common Stock (dollars)	$	0.45		—		—

Average Common Shares Outstanding (in thousands)**
Basic	628,835			627,628		627,628
Diluted	636,764			634,645		634,645
*Includes excise taxes on petroleum product sales:	$	13,371		13,955		13,689
** See Note 12—Earnings Per Share.
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income	Phillips 66
	Millions of Dollars
Years Ended December 31	2012			2011		2010

Net Income	$	4,131		4,780		740
Other comprehensive income (loss)
Defined benefit plans
Prior service cost/credit:
Prior service credit arising during the period	18			—		—
Amortization to net income of prior service cost	1			—		—
Actuarial gain/loss:
Actuarial loss arising during the period	(152		)	(8	)	(8	)
Amortization to net income of net actuarial loss	55			3		2
Plans sponsored by equity affiliates	(33		)	(41	)	(23	)
Income taxes on defined benefit plans	18			17		12
Defined benefit plans, net of tax	(93		)	(29	)	(17	)
Foreign currency translation adjustments	148			28		(95	)
Income taxes on foreign currency translation adjustments	48			(92	)	(4	)
Foreign currency translation adjustments, net of tax	196			(64	)	(99	)
Hedging activities by equity affiliates	1			2		2
Income taxes on hedging activities by equity affiliates	—			(1	)	(1	)
Hedging activities by equity affiliates, net of tax	1			1		1
Other Comprehensive Income (Loss), Net of Tax	104			(92	)	(115	)
Comprehensive Income	4,235			4,688		625
Less: comprehensive income attributable to noncontrolling interests	7			5		5
Comprehensive Income Attributable to Phillips 66	$	4,228		4,683		620
See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet	Phillips 66
	Millions of Dollars
At December 31	2012			2011
Assets
Cash and cash equivalents	$	3,474		—
Accounts and notes receivable (net of allowance of $50 million in 2012 and $13 million in 2011)	8,593			8,354
Accounts and notes receivable—related parties	1,810			1,671
Inventories	3,430			3,466
Prepaid expenses and other current assets	655			457
Total Current Assets	17,962			13,948
Investments and long-term receivables	10,471			10,306
Net properties, plants and equipment	15,407			14,771
Goodwill	3,344			3,332
Intangibles	724			732
Other assets	165			122
Total Assets	$	48,073		43,211

Liabilities
Accounts payable	$	9,731		10,007
Accounts payable—related parties	979			785
Short-term debt	13			30
Accrued income and other taxes	901			1,087
Employee benefit obligations	441			64
Other accruals	417			411
Total Current Liabilities	12,482			12,384
Long-term debt	6,961			361
Asset retirement obligations and accrued environmental costs	740			787
Deferred income taxes	5,444			5,803
Employee benefit obligations	1,325			117
Other liabilities and deferred credits	315			466
Total Liabilities	27,267			19,918

Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2012—631,149,613 shares)
Par value	6			—
Capital in excess of par	18,726			—
Treasury stock (at cost: 2012—7,603,896 shares)	(356		)	—
Retained earnings	2,713			—
Net parent company investment	—			23,142
Accumulated other comprehensive income (loss)	(314		)	122
Total Stockholders' Equity	20,775			23,264
Noncontrolling interests	31			29
Total Equity	20,806			23,293
Total Liabilities and Equity	$	48,073		43,211
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Cash Flows	Phillips 66
	Millions of Dollars
Years Ended December 31	2012			2011		2010
Cash Flows From Operating Activities
Net income	$	4,131		4,780		740
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	913			908		880
Impairments	1,158			472		1,699
Accretion on discounted liabilities	25			21		22
Deferred taxes	221			931		(33	)
Undistributed equity earnings	(872		)	(951	)	(723	)
Net gain on dispositions	(193		)	(1,638	)	(241	)
Other	69			167		(53	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable	(143		)	(186	)	(3,019	)
Decrease (increase) in inventories	55			616		(344	)
Decrease (increase) in prepaid expenses and other current assets	(48		)	28		(2	)
Increase (decrease) in accounts payable	(985		)	58		3,003
Increase (decrease) in taxes and other accruals	(35		)	(200	)	163
Net Cash Provided by Operating Activities	4,296			5,006		2,092

Cash Flows From Investing Activities
Capital expenditures and investments	(1,721		)	(1,022	)	(1,150	)
Proceeds from asset dispositions	286			2,627		662
Advances/loans—related parties	(100		)	—		(200	)
Collection of advances/loans—related parties	—			550		20
Other	—			337		16
Net Cash Provided by (Used in) Investing Activities	(1,535		)	2,492		(652	)

Cash Flows From Financing Activities
Distributions to ConocoPhillips	(5,255		)	(7,471	)	(1,411	)
Issuance of debt	7,794			—		—
Repayment of debt	(1,210		)	(26	)	(26	)
Issuance of common stock	47			—		—
Repurchase of common stock	(356		)	—		—
Dividends paid on common stock	(282		)	—		—
Other	(39		)	(1	)	(3	)
Net Cash Provided by (Used in) Financing Activities	699			(7,498	)	(1,440	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	14			—		—

Net Change in Cash and Cash Equivalents	3,474			—		—
Cash and cash equivalents at beginning of year	—			—		—
Cash and Cash Equivalents at End of Year	$	3,474		—		—
See Notes to Consolidated Financial Statements.

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Consolidated Statement of Changes in Equity													Phillips 66

	Millions of Dollars
	Attributable to Phillips 66
	Common Stock
	Par Value		Capital in Excess of Par		Treasury Stock		Retained Earnings		Net Parent Company Investment		Accum. Other Comprehensive Income (Loss)		Noncontrolling Interests		Total

December 31, 2009	$	—	—		—		—		26,588		329		23		26,940
Net income	—		—		—		—		735		—		5		740
Net transfers to ConocoPhillips	—		—		—		—		(1,536	)	—		—		(1,536	)
Other comprehensive loss	—		—		—		—		—		(115	)	—		(115	)
Distributions to noncontrolling interests and other	—		—		—		—		—		—		(3	)	(3	)
December 31, 2010	—		—		—		—		25,787		214		25		26,026
Net income	—		—		—		—		4,775		—		5		4,780
Net transfers to ConocoPhillips	—		—		—		—		(7,420	)	—		—		(7,420	)
Other comprehensive loss	—		—		—		—		—		(92	)	—		(92	)
Distributions to noncontrolling interests and other	—		—		—		—		—		—		(1	)	(1	)
December 31, 2011	—		—		—		—		23,142		122		29		23,293
Net income	—		—		—		2,999		1,125		—		7		4,131
Net transfers to/from ConocoPhillips	—		—		—		—		(5,707	)	(540	)	—		(6,247	)
Other comprehensive income	—		—		—		—		—		104		—		104
Reclassification of net parent company investment to capital in excess of par	—		18,560		—		—		(18,560	)	—		—		—
Issuance of common stock at the Separation	6		(6	)	—		—		—		—		—		—
Cash dividends paid on common stock	—		—		—		(282	)	—		—		—		(282	)
Repurchase of common stock	—		—		(356	)	—		—		—		—		(356	)
Benefit plan activity	—		172		—		(4	)	—		—		—		168
Distributions to noncontrolling interests and other	—		—		—		—		—		—		(5	)	(5	)
December 31, 2012	$	6	18,726		(356	)	2,713		—		(314	)	31		20,806



	Shares in Thousands
	Common Stock Issued	Treasury Stock
December 31, 2011	—	—
Issuance of common stock at the Separation	625,272	—
Repurchase of common stock	—	7,604
Shares issued—share-based compensation	5,878	—
December 31, 2012	631,150	7,604
See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements	Phillips 66

Note 1—Separation and Basis of Presentation

The Separation

On April 4, 2012, the ConocoPhillips Board of Directors approved the separation of its downstream businesses into an independent, publicly traded company named Phillips 66. In accordance with the Separation and Distribution Agreement, the two companies were separated by ConocoPhillips distributing to its stockholders all 625,272,302 shares of common stock of Phillips 66 after the market closed on April 30, 2012 (the Separation). Each ConocoPhillips shareholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. In conjunction with the Separation, ConocoPhillips received a private letter ruling from the Internal Revenue Service to the effect that, based on certain facts, assumptions, representations and undertakings set forth in the ruling, for U.S. federal income tax purposes, the distribution of Phillips 66 stock was not taxable to ConocoPhillips or U.S. holders of ConocoPhillips common stock, except with respect to cash received in lieu of fractional share interests. Following the Separation, ConocoPhillips retained no ownership interest in Phillips 66, and each company now has separate public ownership, boards of directors and management. A registration statement on Form 10, as amended through the time of its effectiveness, describing the Separation was filed by Phillips 66 with the U.S. Securities and Exchange Commission (SEC) and was declared effective on April 12, 2012 (the Form 10). On May 1, 2012, Phillips 66 stock began trading “regular-way” on the New York Stock Exchange under the “PSX” stock symbol.

Basis of Presentation

Prior to the Separation, our results of operations, financial position and cash flows consisted of ConocoPhillips' refining, marketing and transportation operations; its natural gas gathering, processing, transmission and marketing operations, primarily conducted through its equity investment in DCP Midstream, LLC (DCP Midstream); its petrochemical operations, conducted through its equity investment in Chevron Phillips Chemical Company LLC (CPChem); its power generation operations; and an allocable portion of its corporate costs (together, the “downstream businesses”). These financial statements have been presented as if the downstream businesses had been combined for all periods presented. All intercompany transactions and accounts within the downstream businesses were eliminated. The assets and liabilities have been reflected on a historical cost basis, as all of the assets and liabilities presented were wholly owned by ConocoPhillips and were transferred within the ConocoPhillips consolidated group. The statement of income for periods prior to the Separation includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. These allocations were based primarily on specific identification of time and/or activities associated with the downstream businesses, employee headcount or capital expenditures, and our management believes the assumptions underlying the allocations were reasonable. The combined financial statements may not necessarily reflect all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Separation. All financial information presented after the Separation represents the consolidated results of operations, financial position and cash flows of Phillips 66. Accordingly:

•

Our consolidated statements of income, comprehensive income and cash flows for the year ended December 31, 2012, consist of the consolidated results of Phillips 66 for the eight months ended December 31, 2012, and of the combined results of the downstream businesses for the four months ended April 30, 2012. Our consolidated statements of income, comprehensive income and cash flows for the years ended December 31, 2011 and 2010, consist entirely of the combined results of the downstream businesses.


•	Our consolidated balance sheet at December 31, 2012, consists of the consolidated balances of Phillips 66, while at December 31, 2011, it consists of the combined balances of the downstream businesses.

•

Our consolidated statement of changes in equity for the year ended December 31, 2012, consists of both the combined activity for the downstream businesses prior to April 30, 2012, and the consolidated activity for Phillips 66 completed at and subsequent to the Separation. Our consolidated statement of changes in equity for the years ended December 31, 2011 and 2010, consists entirely of the combined activity of the downstream businesses.

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Note 2—Accounting Policies

▪

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.


▪	Net Parent Company Investment—In the consolidated balance sheet, net parent company investment includes, prior to the Separation, ConocoPhillips’ historical investment in us, our accumulated net earnings after taxes, and the net effect of transactions with, and allocations from, ConocoPhillips.


▪	Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in stockholders' equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency.


▪	Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.


▪	Revenue Recognition—Revenues associated with sales of crude oil, natural gas liquids (NGL), petroleum and chemical products, and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).


▪	Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.


▪	Shipping and Handling Costs—We record shipping and handling costs in purchased crude oil and products. Freight costs billed to customers are recorded as a component of revenue.

▪

Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues and to meet tax-conformity requirements. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials and supplies inventories are valued using the weighted-average-cost method.

▪

Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.


▪	Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the

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balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.


▪	Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset’s properties, plant and equipment and is amortized over the useful life of the assets.

▪

Intangible Assets Other Than Goodwill—Intangible assets with finite useful lives are amortized by the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but are tested at least annually for impairment. Each reporting period, we evaluate the remaining useful lives of intangible assets not being amortized to determine whether events and circumstances continue to support indefinite useful lives. These indefinite-lived intangibles are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable.

▪

Goodwill—Goodwill resulting from a business combination is not amortized but is tested at least annually for impairment. If the fair value of a reporting unit is less than the recorded book value of the reporting unit’s assets (including goodwill), less liabilities, then a hypothetical purchase price allocation is performed on the reporting unit’s assets and liabilities using the fair value of the reporting unit as the purchase price in the calculation. If the amount of goodwill resulting from this hypothetical purchase price allocation is less than the recorded amount of goodwill, the recorded goodwill is written down to the new amount. For purposes of goodwill impairment calculations, Refining and Marketing (R&M) is our only reporting unit.


▪	Depreciation and Amortization—Depreciation and amortization of properties, plants and equipment are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

▪

Impairment of Properties, Plants and Equipment—Properties, plants and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets—generally at an entire refinery complex level. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible. Long-lived assets held for sale are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future volumes, prices, costs, margins, and capital project decisions, considering all available evidence at the date of review.

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▪

Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When indicators exist, the fair value is estimated and compared to the investment carrying value. If any impairment is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate.


▪	Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Major refinery maintenance turnarounds are expensed as incurred.

▪

Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Net gain on dispositions” line of our consolidated statement of income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

▪

Asset Retirement Obligations and Environmental Costs—Fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred. When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related properties, plants and equipment. Over time, the liability is increased for the change in its present value, and the capitalized cost in properties, plants and equipment is depreciated over the useful life of the related asset. For additional information, see Note 11—Asset Retirement Obligations and Accrued Environmental Costs.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties, such as state reimbursement funds, are recorded as assets when their receipt is probable and estimable.

▪

Guarantees—Fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

▪

Stock-Based Compensation—We recognize stock-based compensation expense over the shorter of: (1) the service period (i.e., the time required to earn the award); or (2) the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, which is the minimum time required for an award to not be subject to forfeiture. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.


▪	Income Taxes—For periods prior to the Separation, our taxable income was included in the U.S. federal income tax returns and in a number of state income tax returns of ConocoPhillips. In the accompanying consolidated financial statements for periods prior to the Separation, our provision for income taxes is computed as if we were a stand-alone tax-paying entity.

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Interest related to unrecognized tax benefits is reflected in interest expense, and penalties in operating expenses.

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▪	Taxes Collected from Customers and Remitted to Governmental Authorities—Excise taxes are reported gross within sales and other operating revenues and taxes other than income taxes, while other sales and value-added taxes are recorded net in taxes other than income taxes.


▪	Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in stockholders' equity in the consolidated balance sheet.

Note 3—Changes in Accounting Principles

Comprehensive Income

Effective December 31, 2011, we early adopted Financial Accounting Standards Board (FASB) Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income.” This ASU amends FASB Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring a more prominent presentation of the components of other comprehensive income. We elected the two-statement approach, presenting other comprehensive income in a separate statement immediately following the income statement. On December 23, 2011, the FASB issued ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU No. 2011-05.” ASU 2011-12 defers the ASU 2011-05 requirement to present items reclassified into net income from other comprehensive income. This deferral only impacted the presentation requirement on the consolidated income statement.

Note 4—Variable Interest Entities (VIEs)

We hold significant variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on these VIEs follows:

Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny Refinery. As discussed more fully in Note 7—Investments, Loans and Long-Term Receivables, in August 2009 a call right was exercised to acquire the 50 percent ownership interest in MSLP of the co-venturer, Petróleos de Venezuela S.A. (PDVSA). That exercise has been challenged, and the dispute is being arbitrated. Because the exercise has been challenged by PDVSA, we continue to use the equity method of accounting for MSLP, and the VIE analysis below is based on the ownership and governance structure in place prior to the exercise of the call right. MSLP is a VIE because, in securing lender consents in connection with the Separation, we provided a 100 percent debt guarantee to the lender of the 8.85% senior notes issued by MSLP. PDVSA did not participate in the debt guarantee. In our VIE assessment, this disproportionate debt guarantee, plus other liquidity support provided jointly by us and PDVSA independently of equity ownership, results in MSLP not being exposed to all potential losses. We have determined we are not the primary beneficiary while the call exercise is in dispute because under the partnership agreement the co-venturers jointly direct the activities of MSLP that most significantly impact economic performance. At December 31, 2012, our maximum exposure represented the outstanding principal debt balance of $233 million. Our book value in MSLP at December 31, 2012, was $86 million.

We have a 50 percent ownership interest with a 50 percent governance interest in Excel Paralubes, L.P. (Excel). Excel is a VIE because, in securing lender consents in connection with the Separation, ConocoPhillips provided a 50 percent debt guarantee to the lender of the 7.43% senior secured bonds issued by Excel. We provided a full indemnity to ConocoPhillips for this debt guarantee. Our co-venturer did not participate in the debt guarantee. In our assessment of the VIE, this debt guarantee, plus other liquidity support up to $60 million provided jointly by us and our co-venturer independently of equity ownership, results in Excel not being exposed to all potential losses. We have determined we are not the primary beneficiary because we and our co-venturer jointly direct the activities of Excel that most significantly impact economic performance. We continue to use equity method accounting for this investment. At December 31, 2012, our maximum exposure represented 50 percent of the outstanding principal debt balance of $164 million, or $82 million, plus half of the $60 million liquidity support, or $30 million. Our book value in Excel at December 31, 2012, was $98 million.

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Note 5—Inventories

Inventories at December 31 consisted of the following:



	Millions of Dollars
	2012		2011

Crude oil and petroleum products	$	3,138	3,193
Materials and supplies	292		273
	$	3,430	3,466

Inventories valued on the LIFO basis totaled $2,987 million and $3,046 million at December 31, 2012 and 2011, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $7,700 million and $8,600 million at December 31, 2012 and 2011, respectively.

For our R&M segment, certain reductions in inventory caused liquidations of LIFO inventory values. These liquidations increased net income by approximately $162 million, $155 million and $30 million in 2012, 2011 and 2010, respectively.

Note 6—Assets Held for Sale or Sold

During 2010, we sold certain U.S. marketing assets that had been classified as held-for-sale assets, along with other assets, resulting in before-tax gains totaling $241 million.

In August 2011, we sold our refinery in Wilhelmshaven, Germany, which had been operating as a terminal since the fourth quarter of 2009. The refinery was included in our R&M segment and at the time of disposition had a net carrying value of $211 million, which included $243 million of properties, plants and equipment (PP&E). A $234 million before-tax loss was recognized from this disposition in 2011.

In October 2011, we sold Seaway Products Pipeline Company to DCP Midstream. The total carrying value of the asset, which was included in our R&M segment, was $84 million, consisting of $55 million of PP&E and $29 million of allocated goodwill. The sale resulted in a before-tax gain of $312 million, 50 percent of which was recognized in 2011, while the remaining 50 percent was deferred. Amortization of this deferred gain will commence when DCP Midstream completes its reconfiguration of the pipeline from a products line to an NGL line (named Southern Hills). See Note 7—Investments, Loans and Long-Term Receivables for information about our 2012 investment in Southern Hills.

In December 2011, we sold our ownership interests in Colonial Pipeline Company and Seaway Crude Pipeline Company. The total carrying value of these assets, which were included in our R&M segment, was $348 million, including $104 million of investment in equity affiliates and $244 million of allocated goodwill. A $1,661 million before-tax gain was recognized from these dispositions in 2011.

In June 2012, we sold our refinery located on the Delaware River in Trainer, Pennsylvania, for $229 million. The refinery and associated terminal and pipeline assets were included in our R&M segment and at the time of the disposition had a net carrying value of $38 million, which included $37 million of PP&E, $25 million of allocated goodwill and a $53 million asset retirement obligation. A $189 million before-tax gain was recognized from this disposition in 2012.

In November 2012, we sold the Riverhead Terminal located in Riverhead, New York, for $36 million. The terminal and associated assets were included in our R&M segment and had a net carrying value of $34 million at the time of the disposition, which included $33 million of PP&E and $1 million of inventory. A $2 million before-tax gain was recognized from this disposition in 2012.

Gains and losses from asset sales are included in the “Net gain on dispositions” line in the consolidated income statement.

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Note 7—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:



	Millions of Dollars
	2012		2011

Equity investments	$	10,291	10,233
Long-term receivables	132		68
Other investments	48		5
	$	10,471	10,306

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2012, included:


•	WRB Refining LP—49.6 percent owned business venture with Cenovus Energy Inc. (Cenovus)—owns the Wood River and Borger refineries.


•	DCP Midstream—50 percent owned joint venture with Spectra Energy Corp—owns and operates gas plants, gathering systems, storage facilities and fractionation plants.


•	CPChem—50 percent owned joint venture with Chevron Corporation—manufactures and markets petrochemicals and plastics.


•	Malaysian Refining Company Sdn. Bdh. (MRC)—47 percent owned business venture with Petronas, the Malaysian state oil company—owns the Melaka, Malaysia refinery.


•	Rockies Express Pipeline LLC (REX)—25 percent owned joint venture with Tallgrass Energy Partners L.P. and Sempra Energy Corp.—owns and operates a natural gas pipeline system from Cheyenne, Colorado to Clarington, Ohio.


•	DCP Sand Hills Pipeline, LLC and DCP Southern Hills Pipeline, LLC—one-third owned joint ventures with DCP Midstream and Spectra Energy—own and operate NGL pipeline systems from the Eagle Ford and Midcontinent region to Mont Belvieu, Texas.

Summarized 100 percent financial information for all equity method investments in affiliated companies, combined, was as follows:



	Millions of Dollars
	2012		2011	2010

Revenues	$	55,401	59,044	45,123
Income before income taxes	6,265		6,083	3,659
Net income	6,122		5,742	3,390
Current assets	9,646		8,752	8,515
Noncurrent assets	37,269		34,329	33,923
Current liabilities	8,319		6,837	6,978
Noncurrent liabilities	9,251		10,279	11,957

Our share of income taxes incurred directly by the equity companies is included in equity in earnings of affiliates, and as such is not included in the provision for income taxes in our consolidated financial statements.

At December 31, 2012, retained earnings included $429 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $2,304 million, $2,209 million and $1,110 million in 2012, 2011 and 2010, respectively.

WRB

WRB’s operating assets consist of the Wood River and Borger refineries, located in Roxana, Illinois, and Borger, Texas, respectively. As a result of our contribution of these two assets to WRB, a basis difference was created because the fair value

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of the contributed assets recorded by WRB exceeded their historical book value. The difference is primarily amortized and recognized as a benefit evenly over a period of 26 years, which was the estimated remaining useful life of the refineries’ property, plant and equipment at the closing date. At December 31, 2012, the book value of our investment in WRB was $3,690 million, and the basis difference was $3,707 million. Equity earnings in 2012, 2011 and 2010 were increased by $180 million, $185 million and $243 million, respectively, due to amortization of the basis difference. We are the operator and managing partner of WRB. Cenovus is obligated to contribute $7.5 billion, plus accrued interest, to WRB over a 10-year period that began in 2007.

DCP Midstream

DCP Midstream owns and operates gas plants, gathering systems, storage facilities and fractionation plants. At December 31, 2012, the book value of our equity method investment in DCP Midstream was $1,207 million. DCP Midstream markets a portion of its NGL to us and CPChem under a supply agreement that continues at the current volume commitment with a primary term ending December 31, 2014. This purchase commitment is on an “if-produced, will-purchase” basis and so has no fixed production schedule, but has had, and is expected over the remaining term of the contract to have, a relatively stable purchase pattern. NGL are purchased under this agreement at various published market index prices, less transportation and fractionation fees.

CPChem

CPChem manufactures and markets petrochemicals and plastics. At December 31, 2012, the book value of our equity method investment in CPChem was $3,524 million. We have multiple supply and purchase agreements in place with CPChem, ranging in initial terms from one to 99 years, with extension options. These agreements cover sales and purchases of refined products, solvents, and petrochemical and natural gas liquids feedstocks, as well as fuel oils and gases. Delivery quantities vary by product, and are generally on an “if-produced, will-purchase” basis. All products are purchased and sold under specified pricing formulas based on various published pricing indices.

MRC

MRC’s operating asset is a refinery in Melaka, Malaysia. The refinery operates in merchant mode in which each co-venturer sells crude oil to MRC and purchases the resulting refined product. At December 31, 2012, the book value of our equity method investment in MRC was $498 million. In the fourth quarter of 2012, we recorded a before-tax impairment of $564 million. See Note 10—Impairments, for additional information.

REX

REX owns a natural gas pipeline that runs from northwestern Colorado to eastern Ohio, which became fully operational in November 2009. Long-term, binding firm commitments have been secured for virtually all of the pipeline’s capacity through 2019. At December 31, 2012, the book value of our equity method investment in REX was $268 million. During 2012, we recorded before-tax impairments totaling $480 million on this investment. See Note 10—Impairments, for additional information.

Sand Hills and Southern Hills Pipelines

In the fourth quarter of 2012, we invested $459 million to acquire from DCP Midstream a one-third ownership in DCP Sand Hills Pipeline, LLC and DCP Southern Hills Pipeline, LLC. In December, the first phase of the Sand Hills pipeline, which extends from Eagle Ford into Mont Belvieu, was placed in service. The second phase of the project, with deliveries from the Permian Basin, is expected to be completed in the second quarter of 2013. The Southern Hills pipeline, which is a reconfiguration of the former Seaway refined products line into an NGL pipeline, is also on schedule with service from the Midcontinent region to Mont Belvieu. The reconfiguration is expected to be complete in mid-2013. In 2011, we sold our interest in Seaway Products Pipeline Company to DCP Midstream. A deferred gain on this sale of $156 million will begin to amortize over the life of the Southern Hills pipeline when it commences operations. At December 31, 2012, the book value of investments in Sand Hills and Southern Hills was $262 million and $96 million, respectively.

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Other

MSLP owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by ConocoPhillips and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to supply of crude oil to the Sweeny Refinery triggered the right to acquire PDVSA’s 50 percent ownership interest in MSLP, which was exercised on August 28, 2009. PDVSA has initiated arbitration with the International Chamber of Commerce challenging the exercise of the call right and claiming it was invalid. The arbitral tribunal held hearings on the merits of the dispute in December 2012, and we expect a final ruling in the fourth quarter of 2013. We continue to use the equity method of accounting for our investment in MSLP.

Loans and Long-term Receivables

We enter into agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.

In July 2012, we entered into a market-based shareholder financing agreement for up to $100 million with MRC. During 2012, MRC drew down $100 million against the facility. The advance was recorded as a short-term related party advance with interest income recorded in equity earnings to offset the corresponding interest expense by MRC.

WRB Refining LP fully repaid its outstanding loans from us with payments of $550 million in 2011.

In November 2011, a long-term loan to a non-affiliated company related to seller financing of U.S. retail marketing assets sold in 2009 was refinanced, resulting in a receipt of $365 million. The principal portion of this receipt was included in the “Other” line in the investing section of the consolidated statement of cash flows. As part of the refinancing, we provided loan guarantees in support of $191 million of the total refinancing.

Note 8—Properties, Plants and Equipment

Our investment in PP&E is recorded at cost. In the R&M segment, investments in refining manufacturing facilities are generally depreciated on a straight-line basis over a 25-year life, and pipeline assets over a 45-year life. The company’s investment in PP&E, with the associated accumulated depreciation and amortization (Accum. D&A), at December 31 was:



	Millions of Dollars
	2012				2011*
	Gross PP&E		Accum. D&A	Net PP&E	Gross PP&E	Accum. D&A	Net PP&E
R&M
Refining	$	19,010	6,157	12,853	19,333	6,630	12,703
Transportation	2,394		966	1,428	2,359	931	1,428
Marketing and other	1,479		834	645	1,386	766	620
Total R&M	22,883		7,957	14,926	23,078	8,327	14,751
Midstream	66		50	16	64	51	13
Chemicals	—		—	—	—	—	—
Corporate and Other	880		415	465	14	7	7
	$	23,829	8,422	15,407	23,156	8,385	14,771

*Certain PP&E within the R&M segment have been reclassified between "Refining" and "Marketing and other."

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Note 9—Goodwill and Intangibles

Goodwill

Changes in the carrying amount of goodwill, which is entirely within the R&M segment, were as follows:



	Millions of Dollars
	2012			2011

Balance at January 1	$	3,332		3,633
Goodwill allocated to assets sold	(25		)	(273	)
Tax and other adjustments	37			(28	)
Balance at December 31	$	3,344		3,332

Intangible Assets

Information at December 31 on the carrying value of intangible assets follows:



	Millions of Dollars
	Gross Carrying Amount
	2012		2011
Indefinite-Lived Intangible Assets
Trade names and trademarks	$	494	494
Refinery air and operating permits	207		207
	$	701	701

At year-end 2012, our amortized intangible asset balance was $23 million, compared with $31 million at year-end 2011. Amortization expense was not material for 2012 and 2011, and is not expected to be material in future years.

Note 10—Impairments

During 2012, 2011 and 2010, we recognized the following before-tax impairment charges:



	Millions of Dollars
	2012		2011	2010
R&M
United States	$	45	470	83
International	608		2	1,616
	653		472	1,699
Midstream	480		—	—
Corporate	25		—	—
	$	1,158	472	1,699

2012

We have a 47 percent interest in Malaysia Refining Company Sdn. Bhd. (MRC), which is included in our R&M segment. Following a decline in operating results in the first nine months of 2012, we performed a comprehensive analysis of the fair value of our investment in MRC in the fourth quarter. While this analysis was principally based on our long-range plan, which includes our internal projections of future operating results, it also considered projections of future crude oil prices provided by outside consulting firms as a corroboration of our internal projections. Due to significantly lower estimated future refining margins in this region, driven primarily by assumed increases in future crude oil pricing over the long term, we determined that

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the fair value of our investment in MRC was lower than our carrying value, and that this loss in value was other than temporary. Accordingly, we recorded a $564 million impairment of our investment in MRC.

We have a 25 percent interest in Rockies Express Pipeline LLC (REX), which is included in our Midstream segment. During the second quarter of 2012, our co-venturer recognized a fair value adjustment of a disposal group that included its investment in REX, based on information gathered from its marketing process. After identifying this impairment indicator, we performed our own assessment of the carrying amount of our investment in REX, considering expected future cash flows and the discount rate. Based on this updated information, our internal assessment concluded our investment in REX was impaired, and the decline in fair value was other than temporary. Accordingly, our investment was written down to its fair value, and we recognized a $275 million impairment in the second quarter of 2012. During the third quarter, we were notified of a “right of first refusal” purchase price from the co-venturer as part of its disposal process that indicated a fair value substantially lower than our second-quarter estimate. After considering this additional impairment indicator, we updated our internal assessment of REX's carrying amount. As a result, we recorded an impairment of $205 million in the third quarter of 2012.

During 2012, we recorded an impairment of $43 million on the Riverhead Terminal in our R&M segment and a held-for-sale impairment of $42 million in our R&M segment related to equipment formerly associated with the canceled Wilhelmshaven Refinery upgrade project. See Note 6—Assets Held for Sale or Sold, for additional information. In addition, we recorded an impairment of $25 million on a corporate property.

2011

In 2011, we recorded a $467 million impairment of our refinery and associated pipelines and terminals in Trainer, Pennsylvania. In June 2012, we sold the Trainer Refinery and associated pipeline and terminal assets.

2010

In U.S. R&M, we recorded property impairments of $83 million, which included canceled projects, a power generation facility and planned asset dispositions. In International R&M, we recorded a $1,514 million impairment of our refinery in Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, and a $98 million impairment as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.

Note 11—Asset Retirement Obligations and Accrued Environmental Costs

Asset retirement obligations and accrued environmental costs at December 31 were:



	Millions of Dollars
	2012			2011

Asset retirement obligations	$	314		378
Accrued environmental costs	530			542
Total asset retirement obligations and accrued environmental costs	844			920
Asset retirement obligations and accrued environmental costs due within one year*	(104		)	(133	)
Long-term asset retirement obligations and accrued environmental costs	$	740		787

*Classified as a current liability on the balance sheet, under the caption “Other accruals.”

Asset Retirement Obligations

We record the fair value of a liability for an asset retirement obligation when it is incurred (typically when the asset is installed). When the liability is initially recorded, we capitalize the associated asset retirement cost by increasing the carrying amount of the related PP&E. Over time, the liability increases for the change in its present value, while the capitalized cost depreciates over the useful life of the related asset.

We have asset removal obligations that we are required to perform under law or contract once an asset is permanently taken out of service. Most of these obligations are not expected to be paid until many years in the future and will be funded from general company resources at the time of removal. Our largest individual obligations involve asbestos abatement at refineries.

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During 2012 and 2011, our overall asset retirement obligation changed as follows:



	Millions of Dollars
	2012			2011

Balance at January 1	$	378		332
Accretion of discount	13			15
New obligations	3			3
Changes in estimates of existing obligations	(14		)	52
Spending on existing obligations	(16		)	(20	)
Property dispositions	(53		)	(2	)
Foreign currency translation	3			(2	)
Balance at December 31	$	314		378

Accrued Environmental Costs

Total accrued environmental costs at December 31, 2012 and 2011, were $530 million and $542 million, respectively. The 2012 decrease in total accrued environmental costs is due to payments and settlements during the year exceeding new accruals, accrual adjustments and accretion.

We had accrued environmental costs at December 31, 2012 and 2011 of $275 million and $276 million, respectively, primarily related to cleanup at domestic refineries and underground storage tanks at U.S. service stations; $199 million and $206 million, respectively, associated with nonoperator sites; and $56 million and $60 million, respectively, where the company has been named a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act, or similar state laws. Accrued environmental liabilities are expected to be paid over periods extending up to 30 years. Because a large portion of the accrued environmental costs were acquired in various business combinations, they are discounted obligations. Expected expenditures for acquired environmental obligations are discounted using a weighted-average 5 percent discount factor, resulting in an accrued balance for acquired environmental liabilities of $270 million at December 31, 2012. The expected future undiscounted payments related to the portion of the accrued environmental costs that have been discounted are: $29 million in 2013, $29 million in 2014, $27 million in 2015, $18 million in 2016, $29 million in 2017, and $212 million for all future years after 2017.

Note 12—Earnings Per Share

The numerator of basic earnings per share (EPS) is net income attributable to Phillips 66, reduced by noncancelable dividends paid on unvested share-based employee awards during the vesting period (participating securities). The denominator of basic EPS is the sum of the daily weighted-average number of common shares outstanding during the periods presented and fully vested stock and unit awards that have not yet been issued as common stock. The numerator of diluted EPS is also based on net income attributable to Phillips 66, which is reduced only by dividend equivalents paid on participating securities for which the dividends are more dilutive than the participation of the awards in the earnings of the periods presented. To the extent unvested stock, unit or option awards and vested unexercised stock options are dilutive, they are included with the weighted-average common shares outstanding in the denominator. Treasury stock is excluded from the denominator in both basic and diluted EPS.

On April 30, 2012, 625.3 million shares of our common stock were distributed to ConocoPhillips stockholders in conjunction with the Separation. For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed this amount to be outstanding as of the beginning of each period prior to the Separation presented in the calculation of weighted-average shares. In addition, we have assumed the fully vested stock and unit awards outstanding at April 30, 2012, were also outstanding for each of the periods presented prior to the Separation, resulting in a weighted-average basic share count of 627.6 million shares; and we have assumed the dilutive securities outstanding at April 30, 2012, were also outstanding for each period prior to the Separation, resulting in a weighted-average dilutive share count of 634.6 million shares.

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	2012			2011	2010
Basic EPS Calculation
Allocation of earnings:
Net income attributable to Phillips 66 (millions)	$	4,124		4,775	735
Income allocated to participating securities (millions)	(2		)	—	—
Income available to common stockholders (millions)	$	4,122		4,775	735

Weighted-average common shares outstanding—basic (thousands)	628,835			627,628	627,628

Earnings per share—basic	$	6.55		7.61	1.17

Diluted EPS Calculation
Allocation of earnings:
Net income attributable to Phillips 66 (millions)	$	4,124		4,775	735
Income allocated to participating securities (millions)	—			—	—
Income available to common stockholders (millions)	$	4,124		4,775	735

Weighted-average common shares outstanding—basic (thousands)	628,835			627,628	627,628
Dilutive effect of stock-based compensation (thousands)	7,929			7,017	7,017
Weighted-average common shares outstanding—diluted (thousands)	636,764			634,645	634,645

Earnings per share—diluted	$	6.48		7.52	1.16

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Note 13—Debt

Long-term debt at December 31 was:



	Millions of Dollars
	2012			2011

1.95% Senior Notes due 2015	$	800		—
2.95% Senior Notes due 2017	1,500			—
4.30% Senior Notes due 2022	2,000			—
5.875% Senior Notes due 2042	1,500			—
7.68% Notes due 2012	—			7
Industrial Development Bonds due 2018 through 2022 at 0.09%–0.32% at year-end 2012 and 0.08%–5.75% at year-end 2011	50			234
Term loan due 2014 through 2015 at 1.465% at year-end 2012	1,000			—
Note payable to Merey Sweeny, L.P. due 2020 at 7% (related party)	122			134
Other	1			1
Debt at face value	6,973			376
Capitalized leases	6			14
Net unamortized premiums and discounts	(5		)	1
Total debt	6,974			391
Short-term debt	(13		)	(30	)
Long-term debt	$	6,961		361

Maturities of long-term borrowings, inclusive of net unamortized premiums and discounts, in 2013 through 2017 are: $13 million, $300 million, $1,529 million, $16 million and $1,519 million, respectively.

During March 2012, we issued, through a private placement, $5.8 billion of Senior Notes. The notes are guaranteed by Phillips 66 Company, a wholly owned subsidiary. In connection with the private placement, we and Phillips 66 Company entered into a Registration Rights Agreement with the initial purchasers of the notes pursuant to which we agreed, for the benefit of the holders of the notes, to use our commercially reasonable efforts to file with the SEC and cause to be effective a registration statement with respect to a registered offer to exchange each series of notes for new notes that are guaranteed by Phillips 66 Company with terms substantially identical in all material respects to such series of notes.

In the second quarter of 2012, we retired approximately $185 million of previously existing debt and closed the financing of $2.0 billion of new debt in the form of a three-year amortizing term loan. The term loan bears interest at a variable rate based on referenced rates plus a margin dependent upon the credit rating of our senior unsecured long-term debt as determined from time to time by Standard & Poor's Ratings Services (S&P) and Moody's Investors Service (Moody's). In December 2012, we made a $1.0 billion pre-payment on the term loan.

Credit Facilities

In February 2012, we entered into a five-year revolving credit agreement with a syndicate of financial institutions. Under the terms of the revolving credit agreement, we have a borrowing capacity of up to $4.0 billion. No amount has been drawn under this facility. However, as of December 31, 2012, $51 million in letters of credit had been issued that were supported by this facility.

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amounts; violation of covenants; cross-payment default and cross-acceleration (in each case, to indebtedness in excess of a threshold amount); and a change of control.

Borrowings under the credit agreement will incur interest at the London Interbank Offered Rate (LIBOR) plus a margin based on the credit rating of our senior unsecured long-term debt as determined from time to time by S&P and Moody's. The revolving credit agreement also provides for customary fees, including administrative agent fees and commitment fees.

Trade Receivables Securitization Facility

During April 2012, we established a wholly owned subsidiary to hold trade receivables that are used as collateral for the subsidiary's new borrowing facility. The facility has a term of three years and an aggregate capacity of $1.2 billion. As of December 31, 2012, no cash had been borrowed under the facility, but we had obtained $166 million in letters of credit under the facility that were collateralized by $166 million of the trade receivables held by the subsidiary.

Note 14—Guarantees

At December 31, 2012, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

Guarantees of Joint Venture Debt

In April 2012, in connection with the Separation, we issued a guarantee for 100 percent of the 8.85% senior notes issued by MSLP in July 1999. At December 31, 2012, the maximum potential amount of future payments to third parties under the guarantee is estimated to be $233 million, which could become payable if MSLP fails to meet its obligations under the senior note agreement.

At December 31, 2012, we had other guarantees outstanding for our portion of certain joint venture debt obligations, which have terms of up to 13 years. The maximum potential amount of future payments under the guarantees is approximately $115 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

We have residual value guarantees associated with leases with maximum future potential payments totaling approximately $275 million. We have other guarantees with maximum future potential payment amounts totaling $181 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures and guarantees of the lease payment obligations of a joint venture. These guarantees generally extend up to 12 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, litigation, environmental liabilities, permits and licenses, and employee claims, and real estate indemnity against tenant defaults. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite, and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at December 31, 2012, was $334 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount were $131 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at December 31, 2012. For additional information about environmental liabilities, see Note 15—Contingencies and Commitments.

Indemnification and Release Agreement

In conjunction with, and effective as of, the Separation, we entered into the Indemnification and Release Agreement with ConocoPhillips. This agreement governs the treatment between ConocoPhillips and us of all aspects relating to

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indemnification, insurance, litigation responsibility and management, and litigation document sharing and cooperation arising in connection with the Separation. Generally, the agreement provides for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of ConocoPhillips' business with ConocoPhillips. The agreement also establishes procedures for handling claims subject to indemnification and related matters.

Note 15—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against us in connection with matters that arise in the ordinary course of business. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we record receivables for probable insurance or other third-party recoveries. In the case of income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain. See Note 21—Income Taxes, for additional information about income-tax-related contingencies.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for state sites, we are usually only one of many companies cited at a particular site. Due to such joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the state agencies concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar and time limits.

We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated. We have not reduced these accruals for possible insurance recoveries. In the future, we may be involved in additional environmental assessments, cleanups and proceedings. See Note 11—Asset Retirement Obligations and Accrued Environmental Costs, for a summary of our accrued environmental liabilities.

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Legal Proceedings

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized.

At December 31, 2012, we had performance obligations secured by letters of credit of $1,356 million (of which $166 million was issued under the trade receivables securitization facility, $51 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase and other commitments incident to the ordinary conduct of business.

Long-Term Throughput Agreements and Take-or-Pay Agreements

We have certain throughput agreements and take-or-pay agreements in support of financing arrangements. The agreements typically provide for crude oil transportation to be used in the ordinary course of the company’s business. The aggregate amounts of estimated payments under these various agreements are: 2013—$349 million; 2014—$343 million; 2015—$343 million; 2016—$343 million; 2017—$343 million; and 2018 and after—$4,469 million. Total payments under the agreements were $358 million in 2012, $300 million in 2011 and $96 million in 2010.

Note 16—Derivatives and Financial Instruments

Derivative Instruments

We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates and commodity prices or to capture market opportunities. Since we are not currently using cash-flow hedge accounting, all gains and losses, realized or unrealized, from commodity derivative contracts have been recognized in the consolidated statement of income. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in “Other income” on our consolidated statement of income. Cash flows from all our derivative activity for the periods presented appear in the operating section of the consolidated statement of cash flows.

Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for, and we elect, the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We generally apply this normal purchases and normal sales exception to eligible crude oil, refined product, natural gas and power commodity purchase and sales contracts; however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

Our derivative instruments are held at fair value on our consolidated balance sheet. For further information on the fair value of derivatives, see Note 17—Fair Value Measurements.

Commodity Derivative Contracts—We operate in the worldwide crude oil, refined products, NGL, natural gas and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities, which may move our risk profile away from market average prices.

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The following table indicates the balance sheet line items that include the fair values of commodity derivative assets and liabilities presented net (i.e., commodity derivative assets and liabilities with the same counterparty are netted where the right of setoff exists); however, the balances in the following table are presented gross:



	Millions of Dollars
	2012		2011
Assets
Prepaid expenses and other current assets	$	767	665
Other assets	3		5
Liabilities
Other accruals	766		703
Other liabilities and deferred credits	3		1

Hedge accounting has not been used for any item in the table.

The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated statement of income were:



	Millions of Dollars
	2012		2011		2010

Sales and other operating revenues	$	3	(620	)	(257	)
Equity in earnings of affiliates	6		—		—
Other income	39		12		(33	)
Purchased crude oil and products	32		162		151

Hedge accounting has not been used for any item in the table.

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on our underlying operations. The underlying exposures may be from non-derivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts. As of December 31, 2012, and December 31, 2011, the percentage of our derivative contract volume expiring within the next 12 months was 99 percent for both periods.



	Open Position Long / (Short)
	2012		2011
Commodity
Crude oil, refined products and NGL (millions of barrels)	(8	)	(13	)

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC) derivative contracts and trade receivables.

The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from the sale of products from, or related to, our refinery operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these

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receivables have payment terms of 30 days or less. We continually monitor this exposure and the creditworthiness of the counterparties and recognize bad debt expense based on historical write-off experience or specific counterparty collectability. Generally, we do not require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments, and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us to be offset against amounts due us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if our credit ratings fall below investment grade. Cash is the primary collateral in all contracts; however, many contracts also permit us to post letters of credit as collateral.

The aggregate fair values of all derivative instruments with such credit-risk-related contingent features that were in a liability position were not material at December 31, 2012, or at December 31, 2011.

Note 17—Fair Value Measurements

We carry a portion of our assets and liabilities at fair value that is measured at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

Level 2: Inputs other than quoted prices that are directly or indirectly observable.

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities that are initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. There were no material transfers in or out of Level 1.

Recurring Fair Value Measurements

Financial assets and liabilities reported at fair value on a recurring basis primarily include derivative instruments and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. We value our exchange-traded derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Where exchange-provided prices are adjusted, non-exchange quotes are used or when the instrument lacks sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2. OTC financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management's best estimate of fair value. These contracts are classified as Level 3. Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3. We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

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The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:



	Millions of Dollars
	December 31, 2012					December 31, 2011
	Level 1		Level 2	Level 3	Total	Level 1		Level 2	Level 3	Total
Assets
Commodity derivatives	$	380	385	2	767	389		270	6	665
Rabbi trust assets	50		—	—	50	—		—	—	—
Total assets	430		385	2	817	389		270	6	665

Liabilities
Commodity derivatives	393		372	1	766	428		267	4	699
Total liabilities	393		372	1	766	428		267	4	699
Net assets (liabilities)	$	37	13	1	51	(39	)	3	2	(34	)

The derivative values above are based on analysis of each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the legal right of setoff exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.

As reflected in the table above, Level 3 activity is not material.

Nonrecurring Fair Value Measurements

There were no material fair value impairments for the year ended December 31, 2011. The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition during the year ended December 31, 2012:



	Millions of Dollars
			Fair Value Measurements Using
	Fair Value*		Level 1 Inputs	Level 3 Inputs	Before- Tax Loss
Year Ended December 31, 2012
Net PP&E (held for use)	$	84	84	—	68
Net PP&E (held for sale)	32		32	—	42
Equity method investments	781		—	781	1,044

*Represents the fair value at the time of the impairment.

During 2012, certain equity method investments were determined to have fair values below their carrying amount, and the impairments were considered to be other than temporary. This included an investment in our R&M segment with a book value of $1,062 million, which was written down to its fair value of $498 million, resulting in a before-tax loss of $564 million. In addition, our investment in a natural gas transmission pipeline was written down to a fair value of $283 million, resulting in a before-tax loss of $480 million. The fair values were determined principally by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants.

Also, during 2012, net PP&E held for use related to a terminal and storage facility, with a carrying amount of $76 million, was written down to its fair value of $33 million, resulting in a before-tax loss of $43 million. Net PP&E held for sale related to equipment formerly associated with a canceled refinery upgrade project, with a carrying amount of $74 million, was written

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down to its fair value of $32 million, resulting in a before-tax loss of $42 million. The fair values in each case were primarily determined by negotiated selling prices with third parties. In addition, property with a carrying amount of $76 million was written down to its fair value of $51 million, resulting in a before-tax loss of $25 million. The fair value was based on third party valuations.

Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:


•	Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.


•	Accounts and notes receivable: The carrying amount reported on the balance sheet approximates fair value.


•	Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of our fixed-rate debt is estimated based on quoted market prices as a Level 2 fair value.


•	Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, fair value is estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.


•	Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the InterContinental Exchange Futures, or other traded exchanges.


•	Forward-exchange contracts: Fair values are estimated by comparing the contract rate to the forward rate in effect at the end of the respective reporting periods and approximating the exit price at those dates.

Our commodity derivative and financial instruments were:



	Millions of Dollars
	Carrying Amount			Fair Value
	2012		2011	2012	2011
Financial Assets
Commodity derivatives	$	84	73	84		73
Rabbi trust assets		50	—	50		—
Financial Liabilities
Commodity derivatives		49	52	49		52
Total debt, excluding capital leases		6,968	377	7,558		406

The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of setoff exists). In addition, the December 31, 2012, commodity derivative assets and liabilities appear net of $8 million of obligations to return cash collateral and $42 million of rights to reclaim cash collateral, respectively. The December 31, 2011, commodity derivative liabilities appear net of $55 million of rights to reclaim cash collateral.

Note 18—Equity

Preferred Stock

We have 500 million shares of preferred stock authorized, with a par value of $0.01 per share. No shares of preferred stock were outstanding as of December 31, 2012 or 2011.

Treasury Stock

On July 31, 2012, our Board of Directors authorized the repurchase of up to $1 billion of our outstanding common stock and on December 7, 2012, authorized an additional $1 billion share repurchase. We began purchases under this program, which has no expiration date, in the third quarter of 2012. The shares will be repurchased from time to time in the open market at the company's discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements and the Tax Sharing Agreement entered into in connection with the Separation. We are not obligated to acquire any particular amount of common stock and may commence, suspend or discontinue purchases at any time or from time to time without prior notice. Shares of stock repurchased are held as treasury shares.

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Common Stock Dividends

On February 10, 2013, our Board of Directors declared a quarterly cash dividend of $0.3125 per common share, payable March 1, 2013, to holders of record at the close of business on February 21, 2013.

Note 19—Leases

The company leases ocean transport vessels, tugboats, barges, pipelines, railcars, service station land sites, computers, office buildings, corporate aircraft, land and other facilities and equipment. Certain leases include escalation clauses for adjusting rental payments to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed on us by the leasing agreements with regard to dividends, asset dispositions or borrowing ability. Leased assets under capital leases were not significant in any period presented.

At December 31, 2012, future minimum rental payments due under noncancelable leases were:



	Millions of Dollars

2013	$	424
2014	399
2015	315
2016	173
2017	151
Remaining years	381
Total	1,843
Less: income from subleases*	112
Net minimum operating lease payments	$	1,731
*Includes $47 million related to subleases to related parties.

Operating lease rental expense for the years ended December 31 was:



	Millions of Dollars
	2012		2011	2010

Minimum rentals	$	554	576	652
Contingent rentals	8		5	6
Less: sublease rental income*	93		97	114
	$	469	484	544

*2011 and 2010 restated to include subleases with terms of less than one year.

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Note 20—Employee Benefit Plans

Shared Pension and Postretirement Plans

Prior to the Separation, certain of our U.S. and U.K. employees participated in defined benefit pension plans and postretirement benefit plans (Shared Plans) sponsored by ConocoPhillips, which included participants of other ConocoPhillips subsidiaries. Prior to the Separation, we accounted for such Shared Plans as multiemployer benefit plans. Accordingly, we did not record an asset or liability to recognize the funded status of the Shared Plans on our consolidated balance sheet until the Separation. At the Separation, the assets and liabilities of these Shared Plans, which were allocable to Phillips 66 employees, were transferred to Phillips 66. Plan assets of $2,056 million, benefit obligations of $3,060 million and $869 million of accumulated other comprehensive loss ($540 million, net of tax) were recorded for the plans transferred to us.

Pension and Postretirement Plans

The following table provides a reconciliation of the projected benefit obligations and plan assets for our pension plans and accumulated benefit obligations for our other postretirement benefit plans:



	Millions of Dollars
	Pension Benefits								Other Benefits
	2012					2011			2012		2011
	U.S.			Int'l.		U.S.	Int'l.
Change in Benefit Obligation
Benefit obligation at January 1	$	—		237		—	230		—		—
Service cost	82			22		—	5		4		—
Interest cost	65			25		—	13		5		—
Plan participant contributions	—			2		—	1		—		—
Plan amendments	—			—		—	—		(18	)	—
Actuarial loss	90			83		—	—		2		—
Benefits paid	(78		)	(12	)	—	(10	)	(1	)	—
Liabilities assumed from Separation	2,465			396		—	—		199		—
Foreign currency exchange rate change	—			4		—	(2	)	—		—
Benefit obligation at December 31*	$	2,624		757		—	237		191		—
*Accumulated benefit obligation portion of above at December 31:	$	2,265		563		—	206

Change in Fair Value of Plan Assets
Fair value of plan assets at January 1	$	—		120		—	119		—		—
Actual return on plan assets	91			35		—	(3	)	—		—
Company contributions	37			36		—	12		1		—
Plan participant contributions	—			2		—	1		—		—
Benefits paid	(78		)	(12	)	—	(10	)	(1	)	—
Assets received from Separation	1,712			344		—	—		—		—
Foreign currency exchange rate change	—			2		—	1		—		—
Fair value of plan assets at December 31	$	1,762		527		—	120		—		—

Funded Status at December 31	$	(862	)	(230	)	—	(117	)	(191	)	—

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Amounts recognized in the consolidated balance sheet for our pension and other postretirement benefit plans at December 31, 2012 and 2011, include:



	Millions of Dollars
	Pension Benefits								Other Benefits
	2012					2011			2012		2011
	U.S.			Int'l.		U.S.	Int'l.
Amounts Recognized in the Consolidated Balance Sheet at December 31
Current liabilities	$	(8	)	—		—	—		(3	)	—
Noncurrent liabilities	(854		)	(230	)	—	(117	)	(188	)	—
Total recognized	$	(862	)	(230	)	—	(117	)	(191	)	—

Included in accumulated other comprehensive income at December 31 were the following before-tax amounts that had not been recognized in net periodic benefit cost:



	Millions of Dollars
	Pension Benefits						Other Benefits
	2012				2011		2012		2011
	U.S.		Int'l.		U.S.	Int'l.

Unrecognized net actuarial loss (gain)	$	839	161		—	36	(4	)	—
Unrecognized prior service cost (credit)	15		(12	)	—	—	(15	)	—



	Millions of Dollars
	Pension Benefits								Other Benefits
	2012					2011			2012		2011
	U.S.			Int'l.		U.S.	Int'l.
Sources of Change in Other Comprehensive Income
Net loss arising during the period	$	(78	)	(72	)	—	(8	)	(2	)	—
Amortization of (gain) loss included in income	49			7		—	3		(1	)	—
Net change during the period	$	(29	)	(65	)	—	(5	)	(3	)	—

Prior service credit arising during the period	$	—		—		—	—		18		—
Amortization of prior service cost (credit) included in income	2			(1	)	—	—		—		—
Net change during the period	$	2		(1	)	—	—		18		—

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For our tax-qualified pension plans with projected benefit obligations in excess of plan assets, the projected benefit obligation, the accumulated benefit obligation, and the fair value of plan assets were $3,308 million, $2,777 million, and $2,289 million, respectively, at December 31, 2012, and $237 million, $206 million, and $120 million, respectively, at December 31, 2011. For our unfunded nonqualified key employee supplemental pension plans, the projected benefit obligation and the accumulated benefit obligation were $73 million and $51 million, respectively, at December 31, 2012.

The allocated benefit cost from Shared Plans, as well as the components of net periodic benefit cost associated with plans sponsored by us for 2012, 2011, and 2010 is shown in the table below:



	Millions of Dollars
	Pension Benefits											Other Benefits
	2012					2011			2010			2012		2011	2010
	U.S.			Int'l.		U.S.	Int'l.		U.S.	Int'l.
Components of Net Periodic Benefit Cost
Service cost	$	82		22		—	5		—	5		4		—	—
Interest cost	65			25		—	13		—	12		5		—	—
Expected return on plan assets	(81		)	(21	)	—	(8	)	—	(6	)	—		—	—
Amortization of prior service cost	2			(1	)	—	—		—	—		—		—	—
Recognized net actuarial loss (gain)	49			7		—	3		—	2		(1	)	—	—
Subtotal net periodic benefit cost	117			32		—	13		—	13		8		—	—
Allocated benefit cost from ConocoPhillips	71			13		199	39		234	47		7		19	26
Total net periodic benefit cost	$	188		45		199	52		234	60		15		19	26

In determining net periodic benefit cost, we amortize prior service costs on a straight-line basis over the average remaining service period of employees expected to receive benefits under the plan. For net actuarial gains and losses, we amortize 10 percent of the unamortized balance each year. The amount subject to amortization is determined on a plan-by-plan basis. Amounts included in accumulated other comprehensive income at December 31, 2012, that are expected to be amortized into net periodic benefit cost during 2013 are provided below:



	Millions of Dollars
	Pension Benefits				Other Benefits
	U.S.		Int'l.

Unrecognized net actuarial loss	$	84	16		—
Unrecognized prior service cost (credit)	3		(2	)	(1	)

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The following weighted-average assumptions were used to determine benefit obligations and net periodic benefit costs for years ended December 31:



	Pension Benefits					Other Benefits
	2012			2011		2012	2011
	U.S.		Int'l.	U.S.	Int'l.
Assumptions Used to Determine Benefit Obligations:
Discount rate	3.60	%	4.20	—	5.30	3.70	—
Rate of compensation increase	3.85		3.60	—	2.60	—	—

Assumptions Used to Determine Net Periodic Benefit Cost:
Discount rate	4.20	%	5.10	—	5.40	4.20	—
Expected return on plan assets	7.00		5.80	—	5.80	—	—
Rate of compensation increase	3.75		3.60	—	2.60	—	—

For both U.S. and international pension plans, the overall expected long-term rate of return is developed from the expected future return of each asset class, weighted by the expected allocation of pension assets to that asset class. We rely on a variety of independent market forecasts in developing the expected rate of return for each class of assets.

Our other postretirement benefit plans for health insurance are contributory. Effective December 31, 2012, we terminated the subsidy for retiree medical. On or after January 1, 2013, eligible employees will be able to utilize notional amounts credited to an account during their period of service to the company to pay all, or a portion, of their cost to participate in postretirement health insurance through the company. In general, employees hired after December 31, 2012, will not receive credits to an account, but will have unsubsidized access to health insurance through the plan. The cost of health insurance will be adjusted annually by the company's actuary to reflect actual experience and expected health care cost trends. The measurement of the accumulated benefit obligation assumes a health care cost trend rate of 7.50 percent in 2013 that declines to 5.00 percent by 2023. A one percentage-point change in the assumed health care cost trend rate would be immaterial to Phillips 66.

Plan Assets

The investment strategy for managing pension plan assets is to seek a reasonable rate of return relative to an appropriate level of risk and provide adequate liquidity for benefit payments and portfolio management. We follow a policy of broadly diversifying pension plan assets across asset classes, investment managers, and individual holdings. As a result, our plan assets have no significant concentrations of credit risk. Asset classes that are considered appropriate include equities, fixed income, cash, real estate and insurance contracts. Plan fiduciaries may consider and add other asset classes to the investment program from time to time. The target allocations for plan assets are approximately 63 percent equity securities, 36 percent debt securities and 1 percent in all other types of investments. Generally, the investments in the plans are publicly traded, therefore, minimizing the liquidity risk in the portfolio.

The following is a description of the valuation methodologies used for the pension plan assets.


•	Fair values of equity securities and government debt securities categorized in Level 1 are primarily based on quoted market prices.

•

Fair values of corporate debt securities, agency and mortgage-backed securities and government debt securities categorized in Level 2 are estimated using recently executed transactions and market price quotations. If there have been no market transactions in a particular fixed income security, its fair market value is calculated by pricing models that benchmark the security against other securities with actual market prices. When observable price quotations are not available, fair value is based on pricing models that use something other than actual market prices (e.g., observable inputs such as benchmark yields, reported trades and issuer spreads for similar securities), and these securities are categorized in Level 3 of the fair value hierarchy.


•	Fair values of investments in common/collective trusts are determined by the issuer of each fund based on the fair value of the underlying assets.

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•	Fair values of mutual funds are valued based on quoted market prices, which represent the net asset value of shares held. Certain mutual funds are categorized in Level 2 as they are not valued on a daily basis.


•	Cash and cash equivalents are valued at cost, which approximates fair value.


•	Fair values of derivatives are generally calculated from pricing models with market input parameters from third-party sources.


•	Fair values of insurance contracts are valued at the present value of the future benefit payments owed by the insurance company to the plans' participants.


•	Fair values of real estate investments are valued using real estate valuation techniques and other methods that include reference to third-party sources and sales comparables where available.

The fair values of our pension plan assets at December 31, by asset class, were as follows:



	Millions of Dollars
	U.S.					International
	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
2012
Equity Securities
U.S.	$	529	—	—	529	100	—	—	100
International	340		—	—	340	86	—	—	86
Common/collective trusts	—		237	—	237	—	97	—	97
Mutual funds	—		42	—	42	2	—	—	2
Debt Securities
Government	160		54	—	214	97	—	—	97
Corporate	—		287	1	288	—	—	—	—
Agency and mortgage-backed securities	—		45	—	45	—	—	—	—
Common/collective trusts	—		17	—	17	—	112	—	112
Mutual funds	—		—	—	—	1	—	—	1
Cash and cash equivalents	42		—	—	42	9	—	—	9
Derivatives	—		2	—	2	—	—	—	—
Insurance contracts	—		—	—	—	—	—	15	15
Real estate	—		—	—	—	—	—	7	7
Total*	$	1,071	684	1	1,756	295	209	22	526

* Fair values in the table exclude net receivables related to security transactions of $7 million.

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	Millions of Dollars
	U.S.					International
	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
2011
Equity Securities
U.S.	$	—	—	—	—	—	—	—	—
International	—		—	—	—	—	—	—	—
Common/collective trusts	—		—	—	—	—	56	—	56
Mutual funds	—		—	—	—	—	—	—	—
Debt Securities
Government	—		—	—	—	—	—	—	—
Corporate	—		—	—	—	—	—	—	—
Agency and mortgage-backed securities	—		—	—	—	—	—	—	—
Common/collective trusts	—		—	—	—	—	42	—	42
Mutual funds	—		—	—	—	—	—	—	—
Cash and cash equivalents	—		—	—	—	2	—	—	2
Insurance contracts	—		—	—	—	—	—	15	15
Real estate	—		—	—	—	—	—	5	5
Total	$	—	—	—	—	2	98	20	120

As reflected in the table above, Level 3 activity was not material.

Our funding policy for U.S. plans is to contribute at least the minimum required by the Employee Retirement Income Security Act of 1974 and the Internal Revenue Code of 1986, as amended. Contributions to international plans are subject to local laws and tax regulations. Actual contribution amounts are dependent upon plan asset returns, changes in pension obligations, regulatory environments, and other economic factors. In 2013, we expect to contribute approximately $65 million to our U.S. pension plans and other postretirement benefit plans and $55 million to our international pension plans.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid by us in the years indicated:



	Millions of Dollars
	Pension Benefits			Other Benefits
	U.S.		Int'l.

2013	$	180	13	5
2014	196		17	8
2015	214		18	11
2016	221		23	14
2017	243		25	17
2018-2022	1,306		144	105

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Defined Contribution Plans

During 2012, most U.S. employees were eligible to participate in the Phillips 66 Savings Plan (Savings Plan). Employees could contribute up to 75 percent of their eligible pay, subject to certain statutory limits, in the thrift feature of the Savings Plan to a choice of investment funds. The company matched up to 1.25 percent of eligible pay. The total expense related to participants in the Savings Plan and predecessor plans for Phillips 66 employees, excluding the stock savings feature (discussed below), was $15 million in 2012, and $13 million in 2011 and 2010.

Prior to the Separation, the stock savings feature of the Savings Plan was a leveraged employee stock ownership plan. After the Separation, it was a non-leveraged employee stock ownership plan. Employees could elect to participate in the stock savings feature by contributing 1 percent of eligible pay. Subsequently, they received a proportionate allocation of shares of common stock. The total expense related to participants of Phillips 66 in this stock savings feature and predecessor plans for Phillips 66 employees was $157 million in 2012, $38 million in 2011, and $45 million in 2010, all of which was compensation expense.

The Savings Plan was amended, effective January 1, 2013, to:


•	Provide for a company match of participant contributions up to 5 percent of eligible pay.


•	Eliminate the stock savings feature.


•	Add “Success Share,” a discretionary company contribution to thrift feature participants that can range from 0 to 6 percent of eligible pay, with a target of 2 percent.

Share-Based Compensation Plans

Prior to the Separation, our employees participated in the “2011 Omnibus Stock and Performance Incentive Plan of ConocoPhillips” (the COP Omnibus Plan), under which they were eligible to receive ConocoPhillips stock options, restricted stock units (RSUs) and restricted performance share units (PSUs). Effective on the separation date of April 30, 2012, our employees and non-employee directors began participating in the “Omnibus Stock and Performance Incentive Plan of Phillips 66” (the P66 Omnibus Plan).

The P66 Omnibus Plan authorizes the Human Resources and Compensation Committee of our Board of Directors (the Committee) to grant stock options, stock appreciation rights, stock awards (including restricted stock and RSU awards), cash awards, and performance awards to our employees or non-employee directors and other plan participants. Of the 55 million shares of Phillips 66 common stock issuable under the P66 Omnibus Plan, no more than 40 million shares are available for incentive stock options and no more than 40 million shares are available for awards in stock.

In connection with the Separation, share-based compensation awards granted under the COP Omnibus Plan and held by grantees as of April 30, 2012, were adjusted or substituted as follows. These adjustments were intended to preserve the intrinsic value of the awards as of April 30, 2012.


•	Exercisable awards of stock options and stock appreciation rights were converted in accordance with the Employee Matters Agreement so that the grantee received options to purchase both ConocoPhillips and Phillips 66 common stock.


•	Unexercisable awards of stock options held by Phillips 66 employees were replaced with substitute awards to purchase only Phillips 66 common stock.


•	Restricted stock and PSUs awarded for completed performance periods under the ConocoPhillips Performance Share Program (PSP) were converted in accordance with the Employee Matters Agreement so that the grantee received both ConocoPhillips and Phillips 66 restricted stock and PSUs.


•	Restricted stock and RSUs received under all programs other than the PSP were replaced entirely with Phillips 66 restricted stock and RSUs.

Awards granted in connection with the adjustment and substitution of awards originally issued under the COP Omnibus Plan are a part of the P66 Omnibus Plan and are included in the maximum number of shares of Phillips 66 common stock available for delivery under the P66 Omnibus Plan. The terms and conditions of awards discussed below refer to options, RSUs and PSUs granted prior to the Separation.

The adjustment and substitution of awards resulted in the recognition of $9 million of incremental compensation expense in the second quarter of 2012.

Our share-based compensation programs generally provide accelerated vesting (i.e., a waiver of the remaining period of service required to earn an award) for awards held by employees at the time they become eligible for retirement. For share-based awards granted prior to our adoption of Statement of Financial Accounting Standards No. 123(R), codified into FASB ASC

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Topic 718, “Compensation-Stock Compensation,” we recognize expense over the period of time during which the employee earns the award, accelerating the recognition of expense only when an employee actually retires. For share-based awards granted after our adoption of ASC 718 on January 1, 2006, we recognize share-based compensation expense over the shorter of: the service period (i.e., the stated period of time required to earn the award); or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement, but not less than six months, as this is the minimum period of time required for an award to not be subject to forfeiture.

Some of our share-based awards vest ratably (i.e., portions of the award vest at different times) while some of our awards cliff vest (i.e., all of the award vests at the same time). The company made a policy election under ASC 718 to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Total share-based compensation expense recognized in income and the associated tax benefit for the years ended December 31, were as follows:



	Millions of Dollars
	2012			2011		2010

Compensation cost	$	94		46		44
Tax benefit	(35		)	(18	)	(17	)

Stock Options

Stock options granted under the provisions of the P66 Omnibus Plan and earlier plans permit purchase of our common stock at exercise prices equivalent to the average market price of the stock on the date the options were granted. The options have terms of 10 years and generally vest ratably, with one-third of the options awarded vesting and becoming exercisable on each anniversary date following the date of grant. Options awarded to employees already eligible for retirement vest within six months of the grant date, but those options do not become exercisable until the end of the normal vesting period.

The following summarizes our stock option activity from April 30, 2012 to December 31, 2012:



							Millions of Dollars
	Options		Weighted- Average Exercise Price		Weighted-Average Grant-Date Fair Value		Aggregate Intrinsic Value

Outstanding at April 30, 2012	12,597,240		$	23.06
Granted	—		—		$	—
Forfeited	(140,086	)	32.03
Exercised	(4,045,922	)	16.06				$	123
Expired or canceled	(55,312	)	31.80
Outstanding at December 31, 2012	8,355,920		$	26.24

Vested at December 31, 2012	7,429,422		$	25.78			$	145

Exercisable at December 31, 2012	5,530,006		$	24.52			$	103

All option awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

The weighted-average remaining contractual terms of vested options and exercisable options at December 31, 2012, were 5.56 years and 4.58 years, respectively.

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During 2012, we received $65 million in cash and realized a tax benefit of $12 million from the exercise of options. At December 31, 2012, the remaining unrecognized compensation expense from unvested options held by employees of Phillips 66 was $6 million, which will be recognized over a weighted-average period of 19 months, the longest period being 25 months. The calculations of realized tax benefit, unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.

Though Phillips 66 did not grant any new options in 2012 after the Separation, the following table provides the significant assumptions used to calculate the grant date fair market values of options granted prior to the Separation over the years shown below, as calculated using the Black-Scholes-Merton option-pricing model:



	2012		2011	2010
Assumptions used
Risk-free interest rate	1.62	%	3.10	3.23
Dividend yield	4.00	%	4.00	4.00
Volatility factor	33.30	%	33.40	33.80
Expected life (years)	7.42		6.87	6.65

The ranges of the assumptions used were as follows:



	2012			2011		2010
	High		Low	High	Low	High	Low
Ranges used
Risk-free interest rate	1.62	%	1.62	3.10	3.10	3.23	3.23
Dividend yield	4.00		4.00	4.00	4.00	4.00	4.00
Volatility factor	33.30		33.30	33.40	33.40	33.80	33.80

Prior to the spin, we calculated volatility using the most recent ConocoPhillips end-of-week closing stock prices spanning a period equal to the expected life of the options granted. We periodically calculate the average period of time lapsed between grant dates and exercise dates of past grants to estimate the expected life of new option grants.

Stock Unit Program

Generally, RSUs are granted annually under the provisions of the P66 Omnibus Plan and vest ratably, with one-third of the units vesting in 36 months, one-third vesting in 48 months, and the final third vesting 60 months from the date of grant. In addition to these regularly scheduled annual awards, RSUs are also granted ad hoc to attract or retain key personnel, and the terms and conditions under which these RSUs vest vary by award. Upon vesting, the units are settled by issuing one share of Phillips 66 common stock per unit. Units awarded to employees already eligible for retirement vest within six months of the grant date, but those units are not issued as shares until the end of the normal vesting period. Until issued as stock, most recipients of the units receive a quarterly cash payment of a dividend equivalent. The grant date fair value of these units is deemed equal to the average Phillips 66 stock price on the date of grant. The grant date fair market value of units that do not receive a dividend equivalent while unvested is deemed equal to the average Phillips 66 common stock price on the grant date, less the net present value of the dividends that will not be received.

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The following summarizes our stock unit activity from April 30, 2012 to December 31, 2012:



					Millions of Dollars
	Stock Units		Weighted-Average Grant-Date Fair Value		Total Fair Value


Outstanding at April 30, 2012	5,325,118		$	28.52
Granted	163,407		31.17
Forfeited	(48,783	)	30.33
Issued	(213,132	)	27.74		$	9
Outstanding at December 31, 2012	5,226,610		$	28.62

Not Vested at December 31, 2012	3,643,894		$	28.82

All RSU awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

At December 31, 2012, the remaining unrecognized compensation cost from the unvested RSU awards held by employees of Phillips 66 was $54 million, which will be recognized over a weighted-average period of 33 months, the longest period being 52 months. The calculations of unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.

Performance Share Program

Under the P66 Omnibus Plan, we also annually grant to senior management restricted PSUs that do not vest until either: (i) with respect to awards for periods beginning before 2009, the employee becomes eligible for retirement by reaching age 55 with five years of service; or (ii) with respect to awards for performance periods beginning in 2009, five years after the grant date of the award (although recipients can elect to defer the lapsing of restrictions until retirement after reaching age 55 with five years of service). Accordingly, compensation expense is recognized for these awards beginning on the date of grant and ending on the date the PSUs are scheduled to vest. Since these awards are authorized three years prior to the grant date for employees eligible for such retirement by or shortly after the grant date, we recognize compensation expense over the period beginning on the date of authorization and ending on the date of grant. These PSUs are settled by issuing one share of Phillips 66 common stock per unit. Until issued as stock, recipients of the PSUs receive a quarterly cash payment of a dividend equivalent. In its current form, the first grant of PSUs under this program was in 2006.

The following summarizes our performance share activity from April 30, 2012 to December 31, 2012:



					Millions of Dollars
	Performance Share Stock Units		Weighted-Average Grant-Date Fair Value		Total Fair Value


Outstanding at April 30, 2012	2,972,039		$	34.30
Granted	—		—
Forfeited	(1,300	)	38.04
Issued	(378,465	)	33.89		$	18
Outstanding at December 31, 2012	2,592,274		$	34.36

Not Vested at December 31, 2012	814,421		$	35.19

All PSU awards presented in this table are for Phillips 66 stock only, including those awards held by ConocoPhillips employees.

At December 31, 2012, the remaining unrecognized compensation cost from unvested PSU awards held by employees of Phillips 66 was $15 million, which will be recognized over a weighted-average period of 37 months, the longest period being

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14 years. The calculations of unamortized expense and weighted-average periods include awards based on both Phillips 66 and ConocoPhillips stock held by Phillips 66 employees.

Note 21—Income Taxes

Income taxes charged to income were:



	Millions of Dollars
	2012			2011		2010
Income Taxes
Federal
Current	$	1,993		733		335
Deferred	69			746		484
Foreign
Current	160			126		180
Deferred	45			(9	)	(489	)
State and local
Current	254			133		54
Deferred	(21		)	115		15
	$	2,500		1,844		579

Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for tax purposes. Major components of deferred tax liabilities and assets at December 31 were:



	Millions of Dollars
	2012		2011
Deferred Tax Liabilities
Properties, plants and equipment, and intangibles	$	3,721	3,339
Investment in joint ventures	2,183		2,233
Investment in foreign subsidiaries	386		647
Other	24		107
Total deferred tax liabilities	6,314		6,326
Deferred Tax Assets
Benefit plan accruals	614		44
Inventory	92		78
Asset retirement obligations and accrued environmental costs	234		255
Other financial accruals and deferrals	166		122
Loss and credit carryforwards	313		359
Other	59		4
Total deferred tax assets	1,478		862
Less valuation allowance	329		210
Net deferred tax assets	1,149		652
Net deferred tax liabilities	$	5,165	5,674

Current assets, long-term assets, current liabilities and long-term liabilities included deferred taxes of $307 million, $1 million, $29 million and $5,444 million, respectively, at December 31, 2012, and $171 million, $9 million, $51 million and $5,803 million, respectively, at December 31, 2011.

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With the exception of certain foreign tax credit and separate company loss carryforwards, tax attributes were not allocated to us from ConocoPhillips. The foreign tax credit carryforwards, which have a full valuation allowance against them, begin to expire in 2017. The loss carryforwards, all of which are related to foreign operations, have indefinite carryforward periods.

Valuation allowances have been established to reduce deferred tax assets to an amount that will, more likely than not, be realized. During 2012, valuation allowances increased a total of $119 million. This increase is primarily related to foreign tax credit and foreign loss carryforwards. Based on our historical taxable income, expectations for the future, and available tax-planning strategies, management expects remaining net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and the tax consequences of future taxable income.

As of December 31, 2012, we had undistributed earnings related to foreign subsidiaries and foreign corporate joint ventures of approximately $1.7 billion for which deferred income taxes have not been provided. We plan to reinvest these earnings for the foreseeable future. If these amounts were distributed to the United States, we would be subject to additional U.S. income taxes. Determination of the amount of unrecognized deferred income tax liability is not practicable.

As a result of the Separation and pursuant to the Tax Sharing Agreement with ConocoPhillips, the unrecognized tax benefits related to our operations for which ConocoPhillips was the taxpayer remain the responsibility of ConocoPhillips, and we have indemnified ConocoPhillips for such amounts. Those unrecognized tax benefits are reflected in the following table which shows a reconciliation of the beginning and ending unrecognized tax benefits.



	Millions of Dollars
	2012			2011		2010

Balance at January 1	$	169		166		178
Additions based on tax positions related to the current year	3			11		11
Additions for tax positions of prior years	35			27		88
Reductions for tax positions of prior years	(47		)	(32	)	(46	)
Settlements	(2		)	(2	)	(65	)
Lapse of statute	—			(1	)	—
Balance at December 31	$	158		169		166

Included in the balance of unrecognized tax benefits for 2012, 2011 and 2010 were $125 million, $114 million and $122 million, respectively, which, if recognized, would affect our effective tax rate. With respect to various state unrecognized tax benefits and the related accrued liability, approximately $10 million may be recognized or paid within the next twelve months due to completion of audits.

At December 31, 2012, 2011 and 2010, accrued liabilities for interest and penalties totaled $15 million, $9 million and $16 million, respectively, net of accrued income taxes. Interest and penalties decreased earnings by $6 million in 2012, and benefited earnings by $7 million and $6 million in 2011 and 2010, respectively.

We file tax returns in the U.S. federal jurisdiction and in many foreign and state jurisdictions. Audits in significant jurisdictions are generally complete as follows: United Kingdom (2009), Germany (2008) and United States (2008). Certain issues remain in dispute for audited years, and unrecognized tax benefits for years still subject to or currently undergoing an audit are subject to change. As a consequence, the balance in unrecognized tax benefits can be expected to fluctuate from period to period. Although it is reasonably possible such changes could be significant when compared with our total unrecognized tax benefits, the amount of change is not estimable.

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The amounts of U.S. and foreign income (loss) before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes, were:



	Millions of Dollars							Percent of Pre-tax Income
	2012			2011		2010		2012		2011		2010
Income (loss) before income taxes
United States	$	6,267		6,172		2,283		94.5	%	93.2		173.1
Foreign	364			452		(964	)	5.5		6.8		(73.1	)
	$	6,631		6,624		1,319		100.0	%	100.0		100.0

Federal statutory income tax	$	2,321		2,318		462		35.0	%	35.0		35.0
Goodwill allocated to assets sold	9			96		25		0.1		1.4		1.9
Capital loss utilization	—			(619	)	—		—		(9.3	)	—
Tax on foreign operations	141			(61	)	72		2.1		(0.9	)	5.5
Federal manufacturing deduction	(124		)	(53	)	(15	)	(1.8	)	(0.8	)	(1.1	)
State income tax, net of federal benefit	151			161		45		2.3		2.4		3.4
Other	2			2		(10	)	—		—		(0.8	)
	$	2,500		1,844		579		37.7	%	27.8		43.9

During 2011, we realized a significant tax capital loss, which had not previously been recognized, that was related to the disposition of the legal entity which ultimately held the Wilhelmshaven Refinery assets. The tax benefit of this loss was realized as a reduction of capital gains generated in 2011. During 2012, we impaired a foreign investment for which no tax benefit was recognized. No tax benefit was recognized due to our ownership structure and assertion that the earnings of the foreign subsidiary that holds the investment will be reinvested for the foreseeable future. This item is reflected in “Tax on foreign operations” in the table above.

Due to the Separation, we will file our initial U.S. consolidated income tax returns for the period May 1, 2012, through December 31, 2012. Prior to the Separation, and except for certain state and dedicated foreign entity income tax returns, we were included in the ConocoPhillips income tax returns for all applicable years. After ConocoPhillips files its consolidated return for 2012, we anticipate there will be a settlement in 2013 between us and ConocoPhillips under the Tax Sharing Agreement related to income taxes for the period of 2012 prior to the Separation.

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Note 22—Accumulated Other Comprehensive Income (Loss)

Changes in the balances of each component of accumulated other comprehensive income (loss) were as follows:



	Millions of Dollars
	Defined Benefit Plans			Foreign Currency Translation		Hedging		Accumulated Other Comprehensive Income (Loss)

December 31, 2009	$	(99	)	433		(5	)	329
Other comprehensive income (loss)	(17		)	(99	)	1		(115	)
December 31, 2010	(116		)	334		(4	)	214
Other comprehensive income (loss)	(29		)	(64	)	1		(92	)
December 31, 2011	(145		)	270		(3	)	122
Other comprehensive income (loss)	(93		)	196		1		104
Net transfer from ConocoPhillips*	(540		)	—		—		(540	)
December 31, 2012	$	(778	)	466		(2	)	(314	)

*See Consolidated Statement of Changes in Equity.

Note 23—Cash Flow Information



	Millions of Dollars
	2012		2011	2010
Noncash Investing and Financing Activities
Transfer of PP&E in accordance with the Separation and Distribution Agreement with ConocoPhillips	$	374	—	—
Transfer of employee benefit obligations in accordance with the Separation and Distribution Agreement with ConocoPhillips	1,234		—	—
Increase in deferred tax assets associated with the employee benefit liabilities transferred in accordance with the Separation and Distribution Agreement with ConocoPhillips	461		—	—

Cash Payments
Income taxes*	$	2,183	197	195

*Excludes our share of cash tax payments made directly by ConocoPhillips prior to the Separation on April 30, 2012.

Cash interest payments totaled $176 million in 2012. Cash interest payments were not material for 2011 and 2010.

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Note 24—Other Financial Information



	Millions of Dollars Except Per Share Amounts
	2012			2011		2010
Interest and Debt Expense
Incurred
Debt	$	221		12		5
Other	25			5		—
	246			17		5
Capitalized	—			—		(4	)
Expensed	$	246		17		1

Other Income
Interest income	$	18		33		42
Other, net*	117			12		47
	$	135		45		89
*Includes derivatives-related activities. 2012 also includes a $37 million co-venturer contractual payment related to Rockies Express Pipeline.

Research and Development Expenditures—expensed	$	76		74		56

Advertising Expenses	$	57		63		59

Foreign Currency Transaction (Gains) Losses—after-tax
R&M	$	(24	)	(24	)	60
Midstream	—			—		1
Chemicals	—			—		—
Corporate and Other	—			—		—
	$	(24	)	(24	)	61

Note 25—Related Party Transactions

Significant transactions with related parties were:



	Millions of Dollars
	2012		2011	2010

Operating revenues and other income (a)	$	8,227	9,034	7,411
Gain on dispositions (b)	—		156	—
Purchases (c)	22,448		34,558	26,754
Operating expenses and selling, general and administrative expenses (d)	208		361	401
Net interest expense (e)	8		10	10


(a)	We sold crude oil to MRC. NGL, solvents and petrochemical feedstocks were sold to CPChem, gas oil and hydrogen feedstocks were sold to Excel and refined products were sold primarily to CFJ Properties. Beginning in the third quarter of 2010, CFJ was no longer considered a related party due to the sale of our interest. Crude oil, blendstock and other

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intermediate products were sold to WRB. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters and warehouse facilities.


(b)	In 2011, we sold the Seaway Products Pipeline Company to DCP Midstream for cash proceeds of $400 million, resulting in a before-tax gain of $156 million.

(c)

We purchased refined products from WRB. We purchased natural gas and NGL from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. We purchased refined products from MRC. We also paid fees to various pipeline equity companies for transporting finished refined products. In addition, we paid a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel for use in our refining and marketing businesses.


(d)	We paid utility and processing fees to various affiliates.


(e)	We incurred interest expense on a note payable to MSLP. See Note 7—Investments, Loans and Long-Term Receivables and Note 13—Debt, for additional information on loans with affiliated companies.

Also included in the table above are transactions with ConocoPhillips through April 30, 2012, the effective date of the Separation. These transactions include crude oil purchased from ConocoPhillips as feedstock for our refineries and power sold to ConocoPhillips from our power generation facilities. For 2012, 2011 and 2010, sales to ConocoPhillips, while it was a related party, were $381 million, $1,197 million and $991 million, respectively, while purchases from ConocoPhillips were $5,328 million, $15,798 million and $13,345 million, respectively.

As discussed in Note 1—Separation and Basis of Presentation, the consolidated statement of income includes expense allocations for certain corporate functions historically performed by ConocoPhillips and not allocated to its operating segments, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. Net charges from ConocoPhillips for these services, reflected in selling, general and administrative expenses in the consolidated statement of income, were $70 million, $180 million and $176 million for 2012, 2011 and 2010, respectively.

Net Parent Company Investment

The following is a reconciliation of the amounts presented as “Net transfers to ConocoPhillips” on the consolidated statement of changes in equity and the amounts presented as “Distributions to ConocoPhillips” on the consolidated statement of cash flows.



	Millions of Dollars
	2012			2011		2010

Net transfers to ConocoPhillips per the consolidated statement of changes in equity	$	(5,707	)	(7,420	)	(1,536	)
Non-cash adjustments
Foreign currency translation adjustments on net parent company investment	(118		)	(18	)	136
Net transfers of assets and liabilities with ConocoPhillips	570			(33	)	(11	)
Distributions to ConocoPhillips per the consolidated statement of cash flows	$	(5,255	)	(7,471	)	(1,411	)

In April 2012, we entered into the Separation and Distribution Agreement and several other agreements with ConocoPhillips to effect the Separation and to provide a framework for our relationship with ConocoPhillips. Because the terms of these agreements were entered into in the context of a related party transaction, the terms may not be comparable to terms that would be obtained in a transaction between unrelated parties.

The Separation and Distribution Agreement between us and ConocoPhillips contains the key provisions relating to the separation of our business from ConocoPhillips and the distribution of our common stock to ConocoPhillips stockholders. The Separation and Distribution Agreement identifies the assets that were transferred, liabilities that were assumed and contracts that were assigned to us by ConocoPhillips or by us to ConocoPhillips in the Separation and describes how these transfers,

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assumptions and assignments occurred. In accordance with the Separation and Distribution Agreement, ConocoPhillips determined that our aggregate cash and cash equivalents balance at the separation date of April 30, 2012, should be approximately $2 billion. Accordingly, on April 30, 2012, we made a special cash distribution to ConocoPhillips of $5.95 billion. After subsequent working capital and inventory determinations, an additional cash distribution of $1.87 billion was made to ConocoPhillips in June 2012. After consideration of the cash retained by Phillips 66 at Separation, as well as cash flow impacts of the four months ended April 30, 2012, net distributions to ConocoPhillips in 2012 totaled $5.3 billion.

Note 26—Segment Disclosures and Related Information

We have organized our reporting structure based on the grouping of similar products and services, resulting in three operating segments:

R&M—This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia. At December 31, 2012, we owned or had an interest in 11 refineries in the United States, one in the United Kingdom, one in Ireland, one in Germany, and one in Malaysia. This segment also includes power generation operations. The R&M segment’s "refining" and "marketing, specialties and other" operations are disclosed separately for reporting purposes.


2)	Midstream—This segment gathers, processes, transports and markets natural gas; and transports, fractionates and markets NGL in the United States. The Midstream segment includes our 50 percent equity investment in DCP Midstream.


3)	Chemicals—This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.

Corporate and Other includes general corporate overhead, interest expense, our investments in new technologies and various other corporate activities. Corporate assets include all cash and cash equivalents.

We evaluate performance and allocate resources based on net income attributable to Phillips 66. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment



	Millions of Dollars
	2012			2011		2010
Sales and Other Operating Revenues
R&M
Refining	$	39,437		51,512		36,720
Marketing, Specialties & Other	134,132			136,800		103,250
Intersegment eliminations	(277		)	(509	)	(402	)
R&M	173,292			187,803		139,568
Midstream
Total sales	6,431			8,770		7,383
Intersegment eliminations	(287		)	(499	)	(407	)
Midstream	6,144			8,271		6,976
Chemicals	11			11		11
Corporate and Other	13			3		6
Consolidated sales and other operating revenues	$	179,460		196,088		146,561

Depreciation, Amortization and Impairments
R&M
Refining	$	1,262		1,128		2,302
Marketing, Specialties & Other	281			247		274
Total R&M	1,543			1,375		2,576
Midstream	481			2		2
Chemicals	—			—		—
Corporate and Other	47			3		1
Consolidated depreciation, amortization and impairments	$	2,071		1,380		2,579

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	Millions of Dollars
	2012			2011		2010
Equity in Earnings of Affiliates
R&M
Refining	$	1,542		1,270		589
Marketing, Specialties & Other	77			108		130
Total R&M	1,619			1,378		719
Midstream	323			490		362
Chemicals	1,192			975		684
Corporate and Other	—			—		—
Consolidated equity in earnings of affiliates	$	3,134		2,843		1,765

Income Taxes
R&M
Refining	$	2,059		920		(27	)
Marketing, Specialties & Other	308			559		363
Total R&M	2,367			1,479		336
Midstream	6			210		142
Chemicals	366			252		194
Corporate and Other	(239		)	(97	)	(93	)
Consolidated income taxes	$	2,500		1,844		579

Net Income Attributable to Phillips 66
R&M
Refining	$	3,158		1,533		(466	)
Marketing, Specialties & Other	571			2,315		612
Total R&M	3,729			3,848		146
Midstream	6			403		262
Chemicals	823			716		486
Corporate and Other	(434		)	(192	)	(159	)
Consolidated net income attributable to Phillips 66	$	4,124		4,775		735

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	Millions of Dollars
	2012		2011	2010
Investments In and Advances To Affiliates
R&M
Refining	$	4,571	5,186	5,045
Marketing, Specialties & Other	328		307	394
Total R&M	4,899		5,493	5,439
Midstream	1,868		1,743	1,898
Chemicals	3,524		2,998	2,518
Corporate and Other	—		—	—
Consolidated investments in and advances to affiliates	$	10,291	10,234	9,855

Total Assets
R&M
Refining	$	23,384	24,045	25,289
Marketing, Specialties & Other	10,231		9,913	10,142
Goodwill	3,344		3,332	3,633
Total R&M	36,959		37,290	39,064
Midstream	2,528		2,900	3,128
Chemicals	3,816		2,999	2,732
Corporate and Other	4,770		22	31
Consolidated total assets	$	48,073	43,211	44,955

Capital Expenditures and Investments
R&M
Refining	$	738	770	886
Marketing, Specialties & Other	316		218	188
Total R&M	1,054		988	1,074
Midstream	527		17	68
Chemicals	—		—	—
Corporate and Other	140		17	8
Consolidated capital expenditures and investments	$	1,721	1,022	1,150

Interest Income and Expense
Interest income
R&M	$	—	33	42
Corporate	18		—	—
	18		33	42
Interest and debt expense
Corporate	$	246	17	1

Sales and Other Operating Revenues by Product Line
Refined products	$	141,151	146,834	108,182
Crude oil resales	28,730		38,259	28,836
NGL	8,533		10,024	8,468
Other	1,046		971	1,075
Consolidated sales and other operating revenues by product line	$	179,460	196,088	146,561

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Geographic Information



	Millions of Dollars
	Sales and Other Operating Revenues*				Long-Lived Assets**
	2012		2011	2010	2012	2011	2010

United States	$	120,514	134,499	100,914	22,285	21,196	21,224
United Kingdom	35,361		26,976	20,125	2,018	1,927	1,929
Germany	11,751		10,647	9,070	567	547	849
Other foreign countries	11,834		23,966	16,452	828	1,335	1,262
Worldwide consolidated	$	179,460	196,088	146,561	25,698	25,005	25,264

*Sales and other operating revenues are attributable to countries based on the location of the operations generating the revenues.

**Defined as net properties, plants and equipment plus investments in and advances to affiliated companies.

Note 27—Condensed Consolidating Financial Information

Our $5.8 billion of Senior Notes were issued by Phillips 66, and are guaranteed by Phillips 66 Company, a 100-percent-owned subsidiary. Phillips 66 Company has fully and unconditionally guaranteed the payment obligations of Phillips 66 with respect to these debt securities. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:


•	Phillips 66 and Phillips 66 Company (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).


•	All other nonguarantor subsidiaries.


•	The consolidating adjustments necessary to present Phillips 66's results on a consolidated basis.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

105

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	Millions of Dollars
	Year Ended December 31, 2012
Income Statement	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—		117,574		61,886		—		179,460
Equity in earnings of affiliates	4,284			3,269		445		(4,864	)	3,134
Net gain on dispositions	—			192		1		—		193
Other income (loss)	2			(15	)	148		—		135
Intercompany revenues	1			2,739		23,346		(26,086	)	—
Total Revenues and Other Income	4,287			123,759		85,826		(30,950	)	182,922

Costs and Expenses
Purchased crude oil and products	—			106,687		73,785		(25,989	)	154,483
Operating expenses	—			3,329		759		(56	)	4,032
Selling, general and administrative expenses	4			1,312		447		(41	)	1,722
Depreciation and amortization	—			668		245		—		913
Impairments	—			71		1,087		—		1,158
Taxes other than income taxes	—			5,155		8,587		(1	)	13,741
Accretion on discounted liabilities	—			18		7		—		25
Interest and debt expense	212			29		4		1		246
Foreign currency transaction gains	—			—		(29	)	—		(29	)
Total Costs and Expenses	216			117,269		84,892		(26,086	)	176,291
Income before income taxes	4,071			6,490		934		(4,864	)	6,631
Provision (benefit) for income taxes	(53		)	2,206		347		—		2,500
Net income	4,124			4,284		587		(4,864	)	4,131
Less: net income attributable to noncontrolling interests	—			—		7		—		7
Net Income Attributable to Phillips 66	$	4,124		4,284		580		(4,864	)	4,124

Comprehensive Income	$	3,549		4,217		485		(4,016	)	4,235



	Millions of Dollars
	Year Ended December 31, 2011
Income Statement	Phillips 66		Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—	131,761		64,327		—		196,088
Equity in earnings of affiliates	4,775		2,835		723		(5,490	)	2,843
Net gain (loss) on dispositions	—		1,867		(229	)	—		1,638
Other income	—		10		35		—		45
Intercompany revenues	—		4,887		27,249		(32,136	)	—
Total Revenues and Other Income	4,775		141,360		92,105		(37,626	)	200,614

Costs and Expenses
Purchased crude oil and products	—		124,772		80,157		(32,092	)	172,837
Operating expenses	—		3,278		838		(44	)	4,072
Selling, general and administrative expenses	—		995		414		—		1,409
Depreciation and amortization	—		655		253		—		908
Impairments	—		468		4		—		472
Taxes other than income taxes	—		4,801		9,487		—		14,288
Accretion on discounted liabilities	—		13		8		—		21
Interest and debt expense	—		16		1		—		17
Foreign currency transaction gains	—		(1	)	(33	)	—		(34	)
Total Costs and Expenses	—		134,997		91,129		(32,136	)	193,990
Income before income taxes	4,775		6,363		976		(5,490	)	6,624
Provision for income taxes	—		1,588		256		—		1,844
Net income	4,775		4,775		720		(5,490	)	4,780
Less: net income attributable to noncontrolling interests	—		—		5		—		5
Net Income Attributable to Phillips 66	$	4,775	4,775		715		(5,490	)	4,775

Comprehensive Income	$	4,683	4,683		747		(5,425	)	4,688

106

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	Millions of Dollars
	Year Ended December 31, 2010
Income Statement	Phillips 66		Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—	97,786		48,775		—		146,561
Equity in earnings of affiliates	735		957		770		(697	)	1,765
Net gain on dispositions	—		18		223		—		241
Other income	—		88		1		—		89
Intercompany revenues	—		1,771		17,831		(19,602	)	—
Total Revenues and Other Income	735		100,620		67,600		(20,299	)	148,656

Costs and Expenses
Purchased crude oil and products	—		89,428		55,228		(19,564	)	125,092
Operating expenses	—		3,367		859		(37	)	4,189
Selling, general and administrative expenses	—		978		406		—		1,384
Depreciation and amortization	—		609		271		—		880
Impairments	—		51		1,648		—		1,699
Taxes other than income taxes	—		4,859		9,127		(1	)	13,985
Accretion on discounted liabilities	—		14		8		—		22
Interest and debt expense	—		(1	)	2		—		1
Foreign currency transaction (gains) losses	—		(2	)	87		—		85
Total Costs and Expenses	—		99,303		67,636		(19,602	)	147,337
Income (loss) before income taxes	735		1,317		(36	)	(697	)	1,319
Provision (benefit) for income taxes	—		582		(3	)	—		579
Net income (loss)	735		735		(33	)	(697	)	740
Less: net income attributable to noncontrolling interests	—		—		5		—		5
Net Income (Loss) Attributable to Phillips 66	$	735	735		(38	)	(697	)	735

Comprehensive Income (Loss)	$	620	620		(143	)	(472	)	625

107

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	Millions of Dollars
	At December 31, 2012
Balance Sheet	Phillips 66			Phillips 66 Company		All Other Subsidiaries	Consolidating Adjustments		Total Consolidated
Assets
Cash and cash equivalents	$	—		2,410		1,064	—		3,474
Accounts and notes receivable	47			2,889		8,456	(989	)	10,403
Inventories	—			1,938		1,492	—		3,430
Prepaid expenses and other current assets	11			403		241	—		655
Total Current Assets	58			7,640		11,253	(989	)	17,962
Investments and long-term receivables	28,796			20,784		4,403	(43,512	)	10,471
Net properties, plants and equipment	—			11,714		3,693	—		15,407
Goodwill	—			3,344		—	—		3,344
Intangibles	—			710		14	—		724
Other assets	78			114		9	(36	)	165
Total Assets	$	28,932		44,306		19,372	(44,537	)	48,073

Liabilities and Equity
Accounts payable	$	17		7,014		4,668	(989	)	10,710
Short-term debt	—			13		—	—		13
Accrued income and other taxes	—			245		656	—		901
Employee benefit obligations	—			391		50	—		441
Other accruals	50			279		88	—		417
Total Current Liabilities	67			7,942		5,462	(989	)	12,482
Long-term debt	6,795			165		1	—		6,961
Asset retirement obligations and accrued environmental costs	—			563		177	—		740
Deferred income taxes	—			4,478		1,002	(36	)	5,444
Employee benefit obligations	—			1,094		231	—		1,325
Other liabilities and deferred credits	1,434			1,421		3,936	(6,476	)	315
Total Liabilities	8,296			15,663		10,809	(7,501	)	27,267
Common stock	18,376			25,951		8,287	(34,238	)	18,376
Retained earnings	2,713			3,145		87	(3,232	)	2,713
Accumulated other comprehensive income (loss)	(453		)	(453	)	158	434		(314	)
Noncontrolling interests	—			—		31	—		31
Total Liabilities and Equity	$	28,932		44,306		19,372	(44,537	)	48,073

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	Millions of Dollars
	At December 31, 2011
Balance Sheet	Phillips 66		Phillips 66 Company	All Other Subsidiaries	Consolidating Adjustments		Total Consolidated
Assets
Cash and cash equivalents	$	—	—	—	—		—
Accounts and notes receivable	—		6,497	4,307	(779	)	10,025
Inventories	—		2,048	1,418	—		3,466
Prepaid expenses and other current assets	—		110	347	—		457
Total Current Assets	—		8,655	6,072	(779	)	13,948
Investments and long-term receivables	23,264		12,810	3,623	(29,391	)	10,306
Net properties, plants and equipment	—		11,304	3,467	—		14,771
Goodwill	—		3,332	—	—		3,332
Intangibles	—		713	19	—		732
Other assets	—		105	17	—		122
Total Assets	$	23,264	36,919	13,198	(30,170	)	43,211

Liabilities and Equity
Accounts payable	$	—	6,845	4,726	(779	)	10,792
Short-term debt	—		23	7	—		30
Accrued income and other taxes	—		427	660	—		1,087
Employee benefit obligations	—		13	51	—		64
Other accruals	—		332	79	—		411
Total Current Liabilities	—		7,640	5,523	(779	)	12,384
Long-term debt	—		361	—	—		361
Asset retirement obligations and accrued environmental costs	—		606	181	—		787
Deferred income taxes	—		4,814	989	—		5,803
Employee benefit obligations	—		—	117	—		117
Other liabilities and deferred credits	—		234	2,631	(2,399	)	466
Total Liabilities	—		13,655	9,441	(3,178	)	19,918
Net ConocoPhillips investments	23,142		23,142	3,436	(26,578	)	23,142
Accumulated other comprehensive income	122		122	292	(414	)	122
Noncontrolling interests	—		—	29	—		29
Total Liabilities and Equity	$	23,264	36,919	13,198	(30,170	)	43,211

109

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	Millions of Dollars
	Year Ended December 31, 2012
Statement of Cash Flows	Phillips 66			Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	1,334		7,042		(4,080	)	—		4,296

Cash Flows From Investing Activities
Capital expenditures and investments	—			(861	)	(870	)	10		(1,721	)
Proceeds from asset dispositions	—			240		46		—		286
Advances/loans—related parties	—			—		(100	)	—		(100	)
Collection of advances/loans—related parties	—			—		7		(7	)	—
Other	—			—		—		—		—
Net Cash Used in Investing Activities	—			(621	)	(917	)	3		(1,535	)

Cash Flows From Financing Activities
Contributions from (distributions to) ConocoPhillips	(7,469		)	(3,837	)	6,051		—		(5,255	)
Issuance of debt	7,794			—		—		—		7,794
Repayment of debt	(1,000		)	(208	)	(9	)	7		(1,210	)
Issuance of common stock	47			—		—		—		47
Repurchase of common stock	(356		)	—		—		—		(356	)
Dividends paid on common stock	(282		)	—		—		—		(282	)
Other	(68		)	34		5		(10	)	(39	)
Net Cash Provided by (Used in) Financing Activities	(1,334		)	(4,011	)	6,047		(3	)	699

Effect of Exchange Rate Changes on Cash and Cash Equivalents	—			—		14		—		14

Net Change in Cash and Cash Equivalents	—			2,410		1,064		—		3,474
Cash and cash equivalents at beginning of period	—			—		—		—		—
Cash and Cash Equivalents at End of Period	$	—		2,410		1,064		—		3,474



	Millions of Dollars
	Year Ended December 31, 2011
Statement of Cash Flows	Phillips 66		Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments	Total Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	—	3,038		1,968		—	5,006

Cash Flows From Investing Activities
Capital expenditures and investments	—		(717	)	(305	)	—	(1,022	)
Proceeds from asset dispositions	—		2,517		110		—	2,627
Collection of advances/loans—related parties	—		550		—		—	550
Other	—		51		286		—	337
Net Cash Provided by Investing Activities	—		2,401		91		—	2,492

Cash Flows From Financing Activities
Distributions to ConocoPhillips	—		(5,421	)	(2,050	)	—	(7,471	)
Repayment of debt	—		(18	)	(8	)	—	(26	)
Other	—		—		(1	)	—	(1	)
Net Cash Used in Financing Activities	—		(5,439	)	(2,059	)	—	(7,498	)

Net Change in Cash and Cash Equivalents	—		—		—		—	—
Cash and cash equivalents at beginning of period	—		—		—		—	—
Cash and Cash Equivalents at End of Period	$	—	—		—		—	—

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	Millions of Dollars
	Year Ended December 31, 2010
Statement of Cash Flows	Phillips 66		Phillips 66 Company		All Other Subsidiaries		Consolidating Adjustments	Total Consolidated
Cash Flows From Operating Activities
Net Cash Provided by Operating Activities	$	—	1,370		722		—	2,092

Cash Flows From Investing Activities
Capital expenditures and investments	—		(743	)	(407	)	—	(1,150	)
Proceeds from asset dispositions	—		58		604		—	662
Long-term advances/loans—related parties	—		(200	)	—		—	(200	)
Collection of advances/loans—related parties	—		20		—		—	20
Other	—		—		16		—	16
Net Cash Provided by (Used in) Investing Activities	—		(865	)	213		—	(652	)

Cash Flows From Financing Activities
Distributions to ConocoPhillips	—		(487	)	(924	)	—	(1,411	)
Repayment of debt	—		(18	)	(8	)	—	(26	)
Other	—		—		(3	)	—	(3	)
Net Cash Used in Financing Activities	—		(505	)	(935	)	—	(1,440	)

Net Change in Cash and Cash Equivalents	—		—		—		—	—
Cash and cash equivalents at beginning of period	—		—		—		—	—
Cash and Cash Equivalents at End of Period	$	—	—		—		—	—

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Selected Quarterly Financial Data (Unaudited)



	Millions of Dollars					Per Share of Common Stock**
	Sales and Other Operating Revenues*		Income Before Income Taxes	Net Income	Net Income Attributable to Phillips 66	Net Income Attributable to Phillips 66
	Sales and Other Operating Revenues*		Income Before Income Taxes	Net Income	Net Income Attributable to Phillips 66	Basic	Diluted
2012
First	$	45,783	1,069	638	636	1.01	1.00
Second	46,747		1,894	1,182	1,181	1.88	1.86
Third	42,945		2,449	1,601	1,599	2.53	2.51
Fourth	43,985		1,219	710	708	1.12	1.11

2011
First	$	44,779	1,095	677	676	1.08	1.07
Second	52,594		1,628	1,040	1,039	1.66	1.64
Third	50,610		1,550	1,051	1,049	1.67	1.65
Fourth	48,105		2,351	2,012	2,011	3.20	3.17

*Includes excise taxes on petroleum products sales.

**For comparative purposes, and to provide a more meaningful calculation of weighted-average shares outstanding, we have assumed the shares distributed to ConocoPhillips stockholders in conjunction with the Separation were outstanding as of the beginning of each period prior to the Separation presented in the calculation of weighted-average shares. In addition, we have assumed the dilutive securities outstanding at April 30, 2012, were also outstanding for each of the periods presented prior to the Separation.


Item 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.


Item 9A.	CONTROLS AND PROCEDURES

As of December 31, 2012, with the participation of management, our Chairman, President and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the Act), of Phillips 66's disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman, President and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of December 31, 2012.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the quarterly period ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management's Annual Report on Internal Control Over Financial Reporting

This report is included in Item 8 on page 55 and is incorporated herein by reference.

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

This report is included in Item 8 on page 57 and is incorporated herein by reference.

Item 9B. OTHER INFORMATION

None.

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PART III

Item 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information regarding our executive officers appears in Part I of this report on page 24.

Code of Business Ethics and Conduct for Directors and Employees

We have a Code of Business Ethics and Conduct for Directors and Employees (Code of Ethics), including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. We have posted a copy of our Code of Ethics on the “Governance” section of our Internet website at www.Phillips66.com (within the Investors>Governance section). Any waivers of the Code of Ethics must be approved, in advance, by our full Board of Directors. Any amendments to, or waivers from, the Code of Ethics that apply to our executive officers and directors will be posted on the “Governance” section of our Internet Web site.

All other information required by Item 10 of Part III will be included in, and is incorporated herein by reference to, our Proxy Statement relating to our 2013 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A no later than 120 days after the end of the fiscal year covered by this Form 10-K, which we refer to as our 2013 Definitive Proxy Statement.*

Item 11. EXECUTIVE COMPENSATION

Information required by Item 11 of Part III is incorporated herein by reference from our 2013 Definitive Proxy Statement.*

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by Item 12 of Part III is incorporated herein by reference from our 2013 Definitive Proxy Statement.*

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 of Part III is incorporated herein by reference from our 2013 Definitive Proxy Statement.*

Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 of Part III is incorporated herein by reference from our 2013 Definitive Proxy Statement.*

_________________________

*Except for information or data specifically incorporated herein by reference under Items 10 through 14, other information and data appearing in our 2013 Definitive Proxy Statement are not deemed to be a part of this Annual Report on Form 10‑K or deemed to be filed with the Commission as a part of this report.

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES



(a)	1.	Financial Statements and Supplementary Data The financial statements and supplementary information listed in the Index to Financial Statements, which appears on page 54, are filed as part of this annual report.

	2.	Financial Statement Schedules Schedule II—Valuation and Qualifying Accounts appears below. All other schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements. The financial statements of WRB Refining LP, which follow on pages 116 to 134, are included pursuant to Rule 3-09 of Regulation S-X.

	3.	Exhibits The exhibits listed in the Index to Exhibits, which appears on pages 135 to 137, are filed as part of this annual report.

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SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS (Consolidated)



	Millions of Dollars
Description	Balance at January 1		Charged to Expense	Other (a)		Deductions			Balance at December 31
2012
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	13	36	—		1		(b)	50
Deferred tax asset valuation allowance	210		61	54		4			329
2011
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	7	7	—		(1	)	(b)	13
Deferred tax asset valuation allowance	165		54	(9	)	—			210
2010
Deducted from asset accounts:
Allowance for doubtful accounts and notes receivable	$	16	—	—		(9	)	(b)	7
Deferred tax asset valuation allowance	41		131	(2	)	(5	)		165

(a)Represents acquisitions/dispositions/revisions, net transfers associated with the Separation and the effect of translating foreign financial statements.

(b)Amounts charged off less recoveries of amounts previously charged off.

115

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Index to Financial Statements

FINANCIAL STATEMENTS

WRB Refining LP

Years Ended December 31, 2012, 2011, and 2010

With Report of Independent Auditors

116

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Index to Financial Statements

WRB Refining LP

Financial Statements

Years Ended December 31, 2012, 2011, and 2010



Contents

Report of Independent Auditors	118

Financial Statements

Statement of Operations	119
Balance Sheet	120
Statement of Cash Flows	121
Statement of Partners' Capital	122
Notes to Financial Statements	123

117

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Index to Financial Statements

Report of Independent Auditors

The Management Committee and Partners

WRB Refining LP

We have audited the accompanying financial statements of WRB Refining LP (the Partnership), which comprise the balance sheets as of December 31, 2012 and 2011, and the related statements of operations, partners' capital and cash flows for each of the three years in the period ended December 31, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of WRB Refining LP at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Tulsa, Oklahoma

February 11, 2013

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WRB Refining LP

Statement of Operations



	Year Ended December 31
	2012		2011		2010
	(In Thousands)
Revenues and other income
Related-party sales	$	10,306,627	$	10,050,921	$	6,940,947
Third-party sales	8,014,763		7,472,624		5,933,014
Other operating revenue (loss)	24,648		4,882		(12,614		)
Related-party interest and other income	236,782		279,076		320,299
Total revenues and other income	18,582,820		17,807,503		13,181,646

Costs and expenses
Cost of sales	14,459,184		14,795,819		11,858,804
Operating expenses	963,037		781,522		785,558
Selling, general, and administrative expenses	82,235		66,363		62,880
Depreciation and amortization	475,076		368,544		338,355
Impairments	1,487		88,161		73,082
Taxes other than income taxes	68,825		65,139		42,114
Other expenses	4,880		3,896		3,241
Total costs and expenses	16,054,724		16,169,444		13,164,034

Income before taxes	2,528,096		1,638,059		17,612
Texas margin tax	9,427		7,267		2,144
Net income	$	2,518,669	$	1,630,792	$	15,468

See Notes to Financial Statements.

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WRB Refining LP

Balance Sheet



	December 31
	2012		2011
	(In Thousands)
Assets
Cash and cash equivalents	$	346,152	$	325,825
Accounts receivable	184,390		230,243
Accounts receivable - related parties	335,185		257,129
Inventories	1,127,461		941,648
Other current assets	9,938		4,083
Total current assets	2,003,126		1,758,928

Property, plant, and equipment	12,692,719		12,564,761
Less: Accumulated depreciation and amortization	2,165,748		1,806,619
Net property, plant, and equipment	10,526,971		10,758,142

Intangible assets, net and other	15,911		15,557
Total assets	$	12,546,008	$	12,532,627

Liabilities and partners' capital
Accounts payable	$	164,174	$	119,505
Accounts payable - related parties	952,583		1,320,050
Income and other taxes payable	29,823		36,444
Short-term capital lease obligation	1,830		1,759
Other accruals	3,958		3,454
Total current liabilities	1,152,368		1,481,212

Asset retirement obligations	71,805		103,484
Long-term capital lease obligation	14,237		16,067
Deferred tax liabilities and other	27,535		20,377
Total liabilities	1,265,945		1,621,140

Partners' capital	11,280,063		10,911,487
Total liabilities and partners' capital	$	12,546,008	$	12,532,627

See accompanying notes.

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WRB Refining LP

Statement of Cash Flows



	Year Ended December 31
	2012			2011			2010
	(In Thousands)
Operating activities
Net income	$	2,518,669		$	1,630,792		$	15,468
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	475,076			368,544			338,355
Impairments	1,487			88,161			73,082
Accretion on discounted liabilities	4,143			3,681			3,182
Other	(5,489		)	(7,195		)	(12,182		)
Working capital adjustments:
Decrease (increase) in accounts and notes receivable	(32,203		)	(14,434		)	(24,821		)
Decrease (increase) in inventories	(185,831		)	(221,371		)	(30,795		)
Decrease (increase) in other current assets	(5,856		)	2,126			(1,011		)
Increase (decrease) in accounts payable	(317,779		)	400,501			130,302
Increase (decrease) in taxes payable and other accruals	(6,117		)	23,535			2,872
Net cash provided by operating activities	2,446,100			2,274,340			494,452

Investing activities
Capital expenditures and investments	(273,921		)	(828,168		)	(1,288,790		)
Sale of investment, net	—			—			4,986
Net cash used in investing activities	(273,921		)	(828,168		)	(1,283,804		)

Financing activities
Distributions paid to partners	(2,881,564		)	(1,000,000		)	—
Partner contributions - promissory note repayment	731,471			689,180			649,335
Partner loans	—			—			1,086,000
Repayment of partner loans	—			(1,100,000		)	(686,000		)
Repayment of capital lease obligation	(1,759		)	(653		)	—
Net cash provided by (used in) financing activities	(2,151,852		)	(1,411,473		)	1,049,335

Net change in cash and cash equivalents	20,327			34,699			259,983
Cash and cash equivalents at beginning of year	325,825			291,126			31,143
Cash and cash equivalents at end of year	$	346,152		$	325,825		$	291,126

See accompanying notes.

At December 31, 2012, 2011, and 2010, accrued capital expenditures were $25.0 million, $30.8 million, and $83.2 million, respectively. At December 31, 2012 and 2011, capitalized lease assets totaled $18.5 million. There were no capitalized leases in 2010. The noncash impacts of these expenditures are excluded from above.

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WRB Refining LP

Statement of Partners' Capital



	ConocoPhillips WRB Partner LLC (GP)			Cenovus GPco LLC (GP)			ConocoPhillips (LP)			Cenovus (LP)			Phillips 66 Company (LP)			Total Partners' Capital
	(In Thousands)

Balance as of December 31, 2009	$	—		$	—		$	7,314,825		$	1,611,887		$	—		$	8,926,712
Member contribution - promissory note repayment	—			—			—			649,335			—			649,335
Net income	—			—			7,734			7,734			—			15,468
Equity transfer (LLC to LP restructuring)	14,645			4,538			(14,645		)	(4,538		)	—			—
Balance as of December 31, 2010	14,645			4,538			7,307,914			2,264,418			—			9,591,515
Member contribution - promissory note repayment	—			1,378			—			687,802			—			689,180
Net income	1,631			1,631			813,765			813,765			—			1,630,792
Distributions to members	(1,000		)	(1,000		)	(499,000		)	(499,000		)	—			(1,000,000		)
Balance as of December 31, 2011	15,276			6,547			7,622,679			3,266,985			—			10,911,487
Member contribution - promissory note repayment	—			1,463			—			730,008			—			731,471
Equity transfer	—			—			(7,553,420		)	—			7,553,420			—
Net income	2,519			2,519			397,640			1,256,816			859,175			2,518,669
Distributions to Members	(3,282		)	(3,282		)	(408,317		)	(1,437,500		)	(1,029,183		)	(2,881,564		)
Balance as of December 31, 2012	$	14,513		$	7,247		$	58,582		$	3,816,309		$	7,383,412		$	11,280,063

See accompanying notes.

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WRB Refining LP

Notes to Financial Statements

December 31, 2012

1. Nature of Operations

WRB Refining LLC (the Partnership) was formed on January 3, 2007, as a limited liability partnership owned 50/50 by ConocoPhillips and Cenovus Energy Inc. (Cenovus) (formerly EnCana Corporation). ConocoPhillips has served as operator since WRB's inception. In December 2010, ConocoPhillips and Cenovus agreed to restructure WRB Refining LLC into a limited partnership, named WRB Refining LP (WRB). ConocoPhillips and Cenovus each acquired a 0.1 percent general partner interest and a 49.9 percent limited partner interest in WRB in the restructuring.

In May 2012, ConocoPhillips completed a separation of its downstream businesses into a new company, named Phillips 66. ConocoPhillips contributed its 0.1 percent general partner interest and 49.5 percent of its limited partner interest in WRB to Phillips 66, while retaining a 0.4 percent limited partner interest. Phillips 66 became operator of WRB on May 1, 2012. Unless the context requires otherwise, for ease of reference, ConocoPhillips' interest in WRB prior to May 1, 2012, will be referred to as Phillips 66's interest.

WRB's operating assets consist of the Wood River refinery, located in Roxana, Illinois, and the Borger refinery, located in Borger, Texas. WRB has no employees, and Phillips 66 provides all necessary services under various agreements; see Note 13 — Related-Party Transactions. Per the Partnership Agreement, WRB will continue until the last day of its fiscal period ending in 2100, unless termination is mutually agreed to by Phillips 66 and Cenovus, and thereafter, from year to year, until terminated by a partner.

Each general partner serves jointly on the Management Committee, which has the exclusive power and authority to approve additional partner capital infusions, capital and operating budgets, cash distributions, loans to and from partners, partnership liquidation, and policies. Per the Partnership Agreement, operating results are shared equally by the partners in accordance with their respective partnership interests. A partner with a negative capital account does not have any obligation to the partnership or to any other partner to restore such negative balance. However, as approved by the Management Committee, partners can be required to provide additional cash capital contributions in proportion to their partnership interests.

2. Contribution of Assets to WRB Refining

At formation, Phillips 66 contributed its Wood River and Borger refineries to WRB, while Cenovus US Refinery Holdings (CRH), a subsidiary of Cenovus, contributed a promissory note payable to WRB for $7.5 billion. The promissory note was subsequently transferred to Cenovus US Holdings Inc. (CUH). The fair value of the assets and liabilities contributed by Phillips 66 at the time of formation was determined to be $7.5 billion.

Payments of principal and interest on the CUH $7.5 billion promissory note are made in equal quarterly installments at an annual interest rate of 6 percent. The payments began in January 2007 and are scheduled to end in January 2017. The principal balance of the promissory note at December 31, 2012 and 2011, of $3.6 billion and $4.4 billion, respectively, is recorded as a reduction to Cenovus' partner capital; correspondingly, principal payments are recorded as an increase in Cenovus' partner capital.

3. Accounting Policies

Accounting Principles

The financial statements are in accordance with U.S. generally accepted accounting principles.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from the estimates.

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3. Accounting Policies (continued)

Reclassification

Certain amounts in the 2011 and 2010 financial statements have been reclassified to conform with the 2012 presentation.

Revenue Recognition

Revenues are realized from sales of crude oil, gasoline, distillates, jet fuel, propane, butane, sulfur, coke, asphalt, solvents, other petroleum and chemical products, and other items and are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Shipping and Handling Costs

Shipping and handling costs are recorded in cost of sales. Freight costs billed to customers are recorded as a component of revenue.

Cash Equivalents

Cash equivalents are highly liquid, short-term investments, readily convertible to known amounts of cash, with original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

Inventories

Crude oil and petroleum products inventories are valued at the lower of cost or market in the aggregate on a specific-goods last-in, first-out basis (LIFO). Any necessary lower-of-cost-or-market write-downs are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials and supplies are valued under the weighted-average cost method.

Fair Value Measurements

WRB categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly, through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or WRB's assumptions about pricing by market participants.

Derivative Instruments

All derivative instruments are recorded on the balance sheet at fair value. Recognition and classification of gains or losses that result from recording and adjusting a derivative to fair value are recognized immediately in earnings as the Partnership has not elected to designate any of its derivatives for hedge accounting.

Gains and losses from derivatives are recorded in either sales or cost of sales, depending on the purpose for issuing or holding the derivatives.

In the balance sheet, the fair values of derivative assets and liabilities, including any cash collateral assets and liabilities, are netted if such assets and liabilities are with the same counterparty and netting is permitted subject to a master netting arrangement.

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3. Accounting Policies (continued)

Intangible Assets

Intangible assets with finite useful lives are amortized using the straight-line method over their useful lives. Intangible assets with indefinite useful lives are not amortized but are reviewed at least annually for impairment indicators. In each reporting period, the remaining useful lives of intangible assets not being amortized are evaluated to determine whether events and circumstances continue to support indefinite useful lives. Intangible assets are considered impaired if the fair value of the intangible asset is lower than net book value. The fair value of intangible assets is determined based on quoted market prices in active markets, if available. If quoted market prices are not available, fair value of intangible assets is determined based upon the present values of expected future cash flows using discount rates believed to be consistent with those used by market participants, or upon estimated replacement cost, if expected future cash flows from the intangible asset are not determinable. These assets represent operating permits, emissions credits, and technology licenses, and are included in intangible assets, net and other in the accompanying balance sheets.

Property, Plant, and Equipment

The initial acquisition costs of property, plant, and equipment are capitalized when incurred. Costs include the purchase amount, the cost of constructing or otherwise acquiring equipment or facilities, and the cost of installing the asset and making it ready for its intended use. Property units are identifiable (tangible) parts of an investment that are individually described in the asset records and that perform a separate and complete operation function. They usually have a significant dollar value and are identified as assets that are commonly purchased, replaced, or transferred.

Depreciation and Amortization

Depreciation and amortization of property, plant, and equipment are determined using the straight-line component method over the expected useful life of the capitalized costs of the asset, less any salvage value. Refinery property units representing a significant cost in relation to the total cost of the refinery are depreciated separately over their expected useful lives. The refinery has established 45 separate property unit categories with useful lives ranging from 5 to 60 years. The majority of the investment represents costs for various process, utility, and support systems, which are primarily depreciated between 20 years and 40 years.

Impairment of Property, Plant, and Equipment

Property, plant, and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the future cash flows expected to be generated by an asset group. If indicators of potential impairment exist, an undiscounted cash flow test is performed. If the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as an impairment in the period in which the determination of the impairment is made. Individual assets are grouped for impairment purposes at the lowest level for which identifiable cash flows are largely independent of the cash flows of other groups of assets - generally at an entire refinery complex level. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible. Long-lived assets held for sale are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

Maintenance and Repairs

Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Turnaround (planned major maintenance) costs are expensed when incurred. Maintenance and repairs that result in significant improvements in the asset are capitalized. Inspection work is capitalized if associated with a capitalized property unit replacement.

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3. Accounting Policies (continued)

Property Dispositions

When major units of depreciable property are retired or sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in income. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

Asset Retirement Obligations

The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred, typically when the asset is installed. When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related property, plant, and equipment. Over time, the liability is increased for the change in its present value, and the capitalized cost in property, plant, and equipment is depreciated over the useful life of the related asset. WRB's largest individual obligation involves asbestos abatement at the refineries.

Environmental Costs

WRB is subject to federal, state, and local environmental laws and regulations. These laws and regulations may result in obligations to remove or mitigate the effects on the environment of the placement, storage, disposal, or release of certain chemical, mineral, and petroleum substances at various sites. Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations that do not have a future economic benefit are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Phillips 66 has indemnified WRB for all the environmental obligations at the refineries relating to the time period prior to WRB's formation. At December 31, 2012 and 2011, WRB had no material accrued environmental costs.

Taxes

WRB is structured as a limited partnership, which is a pass-through entity for United States federal income tax purposes. WRB's taxable income or loss, which may vary substantially from the net income or loss reported in the statement of operations, is included in the tax returns of each partner. The reported tax expense reflects the margin tax that applies at the business entity level, including those organized as limited partnerships in the state of Texas. WRB follows the asset and liability method of accounting for taxes. Under this method, deferred taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax bases of the assets and liabilities.

Subsequent Events

Events and transactions subsequent to the balance sheet date have been evaluated through February 11, 2013, the date these financial statements were available to be issued, for potential recognition or disclosure.

4. Interest Cost

Interest cost incurred for the years ended December 31, 2012, 2011, and 2010, was $0.7 million, $3.5 million, and $6.2 million, respectively, of which $3.3 million and $6.1 million for 2011 and 2010, respectively, was capitalized into property, plant, and equipment. The remaining interest cost incurred was included in other expenses in the statement of operations. All interest incurred was paid to related parties.

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5. Inventories

Inventories at December 31 were as follows:



	2012		2011
	(In Thousands)

Crude oil and petroleum products	$	1,086,286	$	903,316
Materials, supplies, and other	41,175		38,332
	$	1,127,461	$	941,648

The excess of current replacement cost over LIFO cost of inventories was estimated as $600.0 million and $720.0 million at December 31, 2012 and 2011, respectively.

During 2012, certain inventory quantity reductions caused a liquidation of LIFO inventory values. This liquidation decreased income before taxes by $2.0 million compared to an increase to income before taxes of $23.0 million in 2011 and $67.0 million during 2010.

6. Property, Plant, and Equipment

WRB's investment in property, plant, and equipment (PP&E) with accumulated depreciation and amortization (D&A) at December 31 was as follows:



	2012						2011
	Gross PP&E		Accumulated D&A		Net PP&E		Gross PP&E		Accumulated D&A		Net PP&E
	(In Thousands)

Borger	$	3,708,012	$	876,454	$	2,831,558	$	3,606,186	$	752,465	$	2,853,721
Wood River	8,983,351		1,289,294		7,694,057		8,958,512		1,054,154		7,904,358
Headquarters	1,356		—		1,356		63		—		63
Total	$	12,692,719	$	2,165,748	$	10,526,971	$	12,564,761	$	1,806,619	$	10,758,142

Impairments of PP&E totaled $1.5 million, $88.2 million, and $73.1 million for 2012, 2011, and 2010, respectively.

The 2012 impairments resulted from two canceled projects at the Wood River refinery and one canceled project at the Borger refinery. These projects were canceled due to revised operating plans that no longer required utilization of the previously capitalized costs, which were written off at project cancellation.

During 2011, the fluid catalytic cracker unit, originally planned as part of the Coker Refinery Expansion (CORE) Project at the Wood River refinery, was canceled due to revised economic projections. As a result, capitalized project costs of $88.1 million were impaired. In 2010, the retirement of a sulfur removal unit at the Borger refinery resulted in an impairment of $73.1 million.

In November 2011, the CORE Project commenced operations. The total project costs were $3.8 billion and consisted of a new coker, vacuum tower, hydrogen plant, and sulfur plant.

Assets under capital leases were not material in 2012 or 2011. The amortization of capital lease assets is included in the depreciation and amortization expense.

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7. Intangibles

The carrying value of amortizable intangible assets at December 31 follows:



	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
	(In Thousands)
Amortizable intangible assets:
Technology licenses	$	14,000	$	6,857	$	7,143
Balance at December 31, 2012	$	14,000	$	6,857	$	7,143

Technology licenses	$	14,000	$	6,300	$	7,700
Balance at December 31, 2011	$	14,000	$	6,300	$	7,700

Amortization expense for 2012, 2011, and 2010 was $0.6 million, $4.6 million, and $4.0 million, respectively. The expected annual amortization expense for 2013 through 2017 is $0.6 million per year.

Indefinite-lived intangible assets, comprising operating permits, had a carrying value of $7.9 million at December 31, 2012 and 2011.

8. Asset Retirement Obligations

Asset retirement obligations at December 31 were as follows:



	2012			2011
	(In Thousands)

Asset retirement obligations	$	75,763		$	106,938
Asset retirement obligation costs due within one year*	(3,958		)	(3,454		)
Long-term asset retirement obligations	$	71,805		$	103,484

*Included in other accruals on the balance sheet.

During 2012 and 2011, the overall asset retirement obligation changed as follows:



	2012			2011
	(In Thousands)

Beginning of period	$	106,938		$	89,930
Accretion of discount	4,143			3,681
Changes in estimates of existing obligations	(31,418		)	19,778
Spending on existing obligations	(3,900		)	(6,451		)
Balance at December 31	$	75,763		$	106,938

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9. Contingencies and Commitments

In the case of all known contingencies, WRB accrues a liability when the loss is probable and the amount is reasonably estimable. WRB does not reduce these liabilities for potential insurance or third-party recoveries. If applicable, receivables are accrued for probable insurance or other third-party recoveries.

Based on currently available information, WRB believes it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on its financial statements. As new facts arise concerning contingencies, WRB reassesses both accrued liabilities and other potential exposures. Estimated future costs related to contingencies are subject to change as events evolve and as additional information becomes available.

Upon formation, WRB became a party to the 2006 consent decree between Phillips 66 and the U.S. government to address alleged violations of the Federal Clean Air Act. WRB is required to make capital expenditures to comply with the consent decree. Remaining obligations for the consent decrees and other regulatory environmental obligations approximated $23 million and were completed in 2012.

10. Derivatives and Financial Instruments

Derivative Instruments

WRB uses financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates and commodity prices. Since WRB is not currently using cash-flow hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the statement of operations. Cash flows from all derivative activity for the periods presented appear in the operating section of the statement of cash flows.

The use of derivative instruments is governed by the Feedstock Supply Agreement and the Refinery Products Marketing Agreement between WRB and Phillips 66, which WRB has appointed operator of the joint venture. These agreements allow Phillips 66 to enter into derivatives on behalf of WRB in a manner consistent with hedging and derivatives policies used by Phillips 66. Phillips 66's Board of Directors prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity for comparable valuations without approval from the Chief Executive Officer of Phillips 66. This prohibition and approval requirement also applies to WRB. WRB is not authorized to enter into speculative trading activities.

Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for, and WRB elects, the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities WRB expects to use or sell over a reasonable period in the normal course of business). WRB generally applies this normal purchases and normal sales exception to eligible purchase and sales contracts; however, WRB may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

WRB's derivative instruments are held at fair value on the balance sheet. For further information on the fair value of derivatives, see Note 11 — Fair Value Measurements.

Commodity Derivative Contracts

WRB operates in the North American crude oil and refined products markets and is exposed to fluctuations in the prices for these commodities. These fluctuations can affect WRB's revenues as well as the cost of operating activities. Generally, WRB's policy is to remain exposed to the market prices of commodities.

WRB uses forwards, futures, and swaps to optimize the value of the supply chain, which may move WRB's risk profile away from market average prices to accomplish the following objectives:


•	Meet customer needs. Consistent with the policy to generally remain exposed to market prices, swap contracts are used to convert fixed-price sales contracts, which are often requested by refined product consumers, to a floating market price.


•	Manage the risk to WRB's cash flows from price exposures on specific crude oil and refined product transactions.


•	Manage the price risk of WRB inventories.

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10. Derivatives and Financial Instruments (continued)

Phillips 66 sources WTI crude oil for several of its owned and operated refineries from Cushing, Oklahoma. As part of these supply activities, Phillips 66 hedges the crude cost using financial derivatives. A portion of the crude supply is delivered to WRB refineries, and that portion of the gain/loss from hedging is allocated to WRB as part of the acquisition cost of the crude oil. The allocated derivative-related acquisition cost included a loss of $1.7 million in 2011 and a gain of $7.2 million in 2012. The tables below in Note 10 reflect derivatives entered into by WRB directly, and do not reflect these derivative-related cost allocations from Phillips 66.



	December 31
	2012		2011
	(In Thousands)
Assets
Other current assets	$	3,731	$	1,278

Liabilities
Other accruals	$	4,617	$	3,889

Hedge accounting has not been used for any items in the table.

The gains (losses) from commodity derivatives incurred, and the line items where they appear on the statement of operations, were as follows:



	2012		2011			2010
	(In Thousands)

Third-party sales	$	6,951	$	(563	)	$	(18,418	)
Cost of sales	983		9,237			21,928

Hedge accounting has not been used for any items in the table.

The table below summarizes WRB's material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposure on WRB's underlying operations. The underlying exposures may be from nonderivative positions such as inventory volumes. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts. As of December 31, 2012 and 2011, the percentage of WRB derivative contract volume expiring within the next 12 months was 99 percent for both periods.



	Open Position Long/(Short)
	December 31 2012		December 31 2011
Commodity
Crude oil, refined products, and natural gas liquids (thousands of barrels)	(301	)	285

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10. Derivatives and Financial Instruments (continued)

Credit Risk

WRB's financial instruments potentially exposed to concentrations of credit risk consist primarily of over-the-counter (OTC) derivative contracts and trade receivables.

The credit risk from OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. These credit exposures are closely monitored, including the continual exposure adjustments that result from market movements. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. Credit risk from NYMEX futures is negligible due to the financial strength of the NYMEX and its member banks. WRB also uses futures and swap contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, WRB is exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

WRB's trade receivables result primarily from its refined product sales under term sales contracts. WRB has a limited number of customers, resulting in a concentration of credit risk. WRB does not generally require collateral to limit the exposure to loss; however, WRB will sometimes use letters of credit, prepayments, and master netting agreements to mitigate credit risk with counterparties that both buy from and sell to WRB, as these agreements permit the amounts owed by WRB or owed to others to be offset against amounts due WRB. Sales to Phillips 66 and Equilon Enterprises LLC represent the majority of WRB's revenue at 56 percent and 27 percent in 2012, 57 percent and 27 percent in 2011, and 54 percent and 29 percent in 2010, respectively. The majority of receivables have payment terms of 30 days or less, and this exposure and the creditworthiness of the counterparties are continuously monitored.

As of December 31, 2012 and 2011, WRB had no derivative instruments in a liability position that contain credit-contingent collateral features.

11. Fair Value Measurements

WRB carries a portion of assets and liabilities at fair value that are measured at the reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:


•	Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities


•	Level 2: Inputs other than quoted prices that are directly or indirectly observable


•	Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities

Recurring Fair Value Measurements

Financial assets and liabilities reported at fair value on a recurring basis primarily include derivative instruments. WRB values exchange-traded derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. When exchange-provided prices are adjusted, nonexchange quotes are used, or when the instrument lacks sufficient liquidity, WRB generally classifies those exchange-cleared contracts as Level 2. OTC financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities which result in management's best estimate of fair value. These contracts are classified as Level 3. WRB uses a midmarket pricing convention (the midpoint between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

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11. Fair Value Measurements (continued)

The fair value hierarchy for derivative assets and liabilities accounted for at fair value on a recurring basis was as follows:



	December 31, 2012										December 31, 2011
	Level 1			Level 2		Level 3		Total			Level 1			Level 2			Level 3		Total
	(In Thousands)
Assets
Commodity derivatives	$	3,731		$	—	$	—	$	3,731		$	599		$	679		$	—	$	1,278

Liabilities
Commodity derivatives	4,617			—		—		4,617			2,454			1,435			—		3,889
Net assets (liabilities)	$	(886	)	$	—	$	—	$	(886	)	$	(1,855	)	$	(756	)	$	—	$	(2,611	)

As reflected in the table above, Level 3 activity is not material.

Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:


•	Cash and cash equivalents: The carrying amount reported on the balance sheet approximates fair value.


•	Accounts and notes receivable: The carrying amount reflects normal credit terms and management's assessment of collectability and approximates fair value.


•	Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period-end. When forward market prices are not available, fair value is estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.


•	Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the InterContinental Exchange Futures, or other traded exchanges.

Certain commodity derivative and financial instruments were as follows:



	Carrying Amount				Fair Value
	December 31 2012		December 31 2011		December 31 2012		December 31 2011
	(In Thousands)
Financial Assets
Commodity derivatives	$	—	$	117	$	—	$	117

Financial Liabilities
Commodity derivatives	—		—		—		—
Total debt, excluding capital leases	—		377		—		406

The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of offset exists). In 2012 and 2011, commodity derivative liabilities also appear net of $0.9 million and $2.7 million of rights to reclaim cash collateral, respectively. In 2012, the combined effect of netting for right of offset and collateral reduces both commodity derivative assets and liabilities to zero.

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12. Leases

WRB leases railcars, computers, office buildings, and other facilities and equipment. Certain leases include escalation clauses for adjusting rentals to reflect changes in price indices, as well as renewal options and/or options to purchase the leased property for the fair market value at the end of the lease term. There are no significant restrictions imposed by the leasing agreements in regard to dividends, asset dispositions, or borrowing ability. At December 31, 2012, future minimum rental payments due under noncancelable operating leases were as follows:



	(In Thousands)

2013	$	6,070
2014	5,789
2015	5,726
2016	5,668
2017	4,124
Remaining years	1,879
Net minimum operating lease payments	$	29,256

Operating lease rental expense for the years ended December 31, 2012, 2011, and 2010, was $13.2 million, $7.8 million, and $3.4 million, respectively.

13. Related-Party Transactions

At December 31, significant transactions with related parties were as follows:



	2012		2011		2010
	(In Thousands)

Operating/Other revenues (a)(d)	$	10,541,927	$	10,324,759	$	7,254,711
Cost of sales (b)(d)	13,853,123		14,290,159		11,522,842
Operating expenses and selling, general, and administrative expenses (c)	429,626		433,584		465,524

(a)

WRB sells petroleum finished products to Phillips 66 under the terms of existing agreements. Interest income is earned from CUH related to CUH's promissory note; see Note 2 — Contribution of Assets to WRB Refining. In 2012, 2011 and 2010, this amount totaled $235.3 million, $278.2 million and $318.7 million, respectively. Interest income receivable was $54.7 million and $65.6 million at December 31, 2012 and 2011, respectively, and is included in accounts receivable - related parties. Certain revenues for which Phillips 66 acts as an agent which were previously classified as related-party sales, are now classified as third-party sales.


(b)	Crude oil, natural gas, natural gas liquids, and other feedstocks are purchased from Phillips 66 for use in refinery processes as per the Feedstock Supply Agreement. Fees are paid to various pipeline companies related to Phillips 66 for transporting crude oil and finished refined products.


(c)	WRB pays Phillips 66 for payroll and benefits related to refinery personnel, G&A from various Phillips 66 corporate service providers, and natural gas that Phillips 66 acquired for the refineries.

(d)

A portion of WRB's economic hedging activities are done through derivative transactions with Phillips 66. As of December 31, 2012, there are no unrealized derivative assets with Phillips 66 reflected on the balance sheet. As of December 31, 2011, unrealized derivative assets of $0.1 million with Phillips 66 are reflected in other assets on the balance sheet. In 2012, derivative transactions with Phillips 66 resulted in $0.4 million in gains, reflected in cost of sales. In 2011, derivative transactions with Phillips 66 resulted in $5.7 million in gains, reflecting a $4.4 million loss in revenues along with a $10.1 million gain in cost of sales. In 2010, derivative transactions with Phillips 66 resulted in $4.9 million in losses, which are reflected in revenues.

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14. Taxes

Texas margin tax was $9.4 million, $7.3 million, and $2.1 million for 2012, 2011, and 2010, respectively, resulting in an effective tax rate of 0.4 percent, 0.4 percent, and 12.2 percent for 2012, 2011, and 2010, respectively. The change in the effective tax rate between 2010, 2011, and 2012 reflects the fact that the Texas margin tax is a revenue-based tax.

As of December 31, 2012, WRB had no liability reported for unrecognized tax benefits. Any interest and penalties related to taxes are included in the provision for taxes. Such interest and penalties were immaterial in all periods presented.

At December 31, 2012 and 2011, WRB had $27.0 million and $19.5 million, respectively, of net deferred tax liability, derived principally from the taxable temporary difference attributable to property, plant, and equipment.

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PHILLIPS 66

INDEX TO EXHIBITS



		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

2.1	Separation and Distribution Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	2.1	05/01/12	001-35349

3.1	Amended and Restated Certificate of Incorporation of Phillips 66.	8-K	3.1	05/01/12	001-35349

3.2	Amended and Restated By-Laws of Phillips 66.	8-K	3.2	05/01/12	001-35349

4.1	Indenture, dated as of March 12, 2012, among Phillips 66, as issuer, Phillips 66 Company, as guarantor, and The Bank of New York Mellon Trust Company, N.A., as trustee, in respect of senior debt securities of Phillips 66.	10	4.3	04/05/12	001-35349

4.2*	Form of the terms of the 1.950% Senior Notes due 2015, the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042, including the form of the 1.950% Senior Notes due 2015, the 2.950% Senior Notes due 2017, the 4.300% Senior Notes due 2022 and the 5.875% Senior Notes due 2042.

10.1	Credit Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders named therein, dated as of February 22, 2012.	10	4.1	03/01/12	001-35349

10.2	Term Loan Agreement among Phillips 66, Phillips 66 Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders named therein, dated as of February 22, 2012.	10	4.2	03/01/12	001-35349

10.3	Receivables Purchase Agreement, dated as of April 27, 2012, among Phillips 66 Receivables Funding LLC, Phillips 66 Company, Royal Bank of Canada, as Administrative Agent and Structuring Agent, certain committed purchasers and conduit purchasers that are parties thereto from time to time and the other parties thereto from time to time.	8-K	10.6	05/01/12	001-35349

10.4	Purchase and Contribution Agreement, dated as of April 27, 2012, by and between Phillips 66 Company and Phillips 66 Receivables Funding LLC.	8-K	10.7	05/01/12	001-35349

10.5	Third Amended and Restated Limited Liability Company Agreement of Chevron Phillips Chemical Company LLC, effective as of May 1, 2012.	10-Q	10.14	08/03/12	001-35349

10.6	Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated July 5, 2005, by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation.	10	10.12	03/01/12	001-35349

10.7	First Amendment to Second Amended and Restated Limited Liability Company Agreement of Duke Energy Field Services, LLC, dated August 11, 2006, by and between ConocoPhillips Gas Company and Duke Energy Enterprises Corporation.	10	10.13	03/01/12	001-35349

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

10.8	Second Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated February 1, 2007, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.	10	10.14	03/01/12	001-35349

10.9	Third Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated April 30, 2009, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.	10	10.15	03/01/12	001-35349

10.10	Fourth Amendment to Second Amended and Restated Limited Liability Company Agreement of DCP Midstream, LLC (formerly Duke Energy Field Services, LLC), dated November 9, 2010, by and between ConocoPhillips Gas Company, Spectra Energy DEFS Holding, LLC, and Spectra Energy DEFS Holding Corp.	10	10.16	03/01/12	001-35349

10.11	Indemnification and Release Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.1	05/01/12	001-35349

10.12	Intellectual Property Assignment and License Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.2	05/01/12	001-35349

10.13	Tax Sharing Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.3	05/01/12	001-35349

10.14	Employee Matters Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.4	05/01/12	001-35349

10.15	Transition Services Agreement between ConocoPhillips and Phillips 66, dated April 26, 2012.	8-K	10.5	05/01/12	001-35349

10.16	Omnibus Stock and Performance Incentive Plan of Phillips 66.**	S-8	4.1	05/01/12	333-181080

10.17	Phillips 66 Key Employee Supplemental Retirement Plan.**	10-Q	10.15	08/03/12	001-35349

10.18*	First Amendment to the Phillips 66 Key Employee Supplemental Retirement Plan.**

10.19	Phillips 66 Executive Severance Plan.**	10-Q	10.16	08/03/12	001-35349

10.20*	First Amendment to the Phillips 66 Executive Severance Plan.**

10.21	Phillips 66 Deferred Compensation Plan for Non-Employee Directors.**	10-Q	10.17	08/03/12	001-35349

10.22	Phillips 66 Key Employee Deferred Compensation Plan-Title I.**	10-Q	10.18	08/03/12	001-35349

10.23	Phillips 66 Key Employee Deferred Compensation Plan-Title II.**	10-Q	10.19	08/03/12	001-35349

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		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.

10.24*	First Amendment to the Phillips 66 Key Employee Deferred Compensation Plan Title II.**

10.25	Phillips 66 Defined Contribution Make-Up Plan Title I.**	10-Q	10.20	08/03/12	001-35349

10.26*	Phillips 66 Defined Contribution Make-Up Plan Title II.**

10.27*	Phillips 66 Key Employee Change in Control Severance Plan.**

10.28	Annex to the Phillips 66 Nonqualified Deferred Compensation Arrangements.**	10-Q	10.23	08/03/12	001-35349

10.29*	Form of Stock Option Award Agreement under the Omnibus Stock and Performance Incentive Plan of Phillips 66.**

10.30*	Form of Restricted Stock or Restricted Stock Unit Award Agreement under the Omnibus Stock and Performance Incentive Plan of Phillips 66.**

10.31*	Form of Performance Share Unit Award Agreement under the Omnibus Stock and Performance Incentive Plan of Phillips 66.**

12*	Computation of Ratio of Earnings to Fixed Charges.

21*	List of Subsidiaries of Phillips 66.

23.1*	Consent of Ernst & Young LLP, independent registered public accounting firm.

23.2*	Consent of Ernst & Young LLP, independent auditors.

31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32*	Certifications pursuant to 18 U.S.C. Section 1350.

101.INS*	XBRL Instance Document.

101.SCH*	XBRL Schema Document.

101.CAL*	XBRL Calculation Linkbase Document.

101.LAB*	XBRL Labels Linkbase Document.

101.PRE*	XBRL Presentation Linkbase Document.

101.DEF*	XBRL Definition Linkbase Document.

*Filed herewith.

**Management contracts and compensatory plans or arrangements.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	PHILLIPS 66



February 22, 2013	/s/ Greg C. Garland
	Greg C. Garland Chairman of the Board of Directors, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 22, 2013, on behalf of the registrant by the following officers in the capacity indicated and by a majority of directors.



Signature		Title



/s/ Greg C. Garland		Chairman of the Board of Directors, President
Greg C. Garland		and Chief Executive Officer
		(Principal executive officer)


/s/ Greg G. Maxwell		Executive Vice President, Finance
Greg G. Maxwell		and Chief Financial Officer
		(Principal financial officer)


/s/ C. Doug Johnson		Vice President and Controller
C. Doug Johnson		(Principal accounting officer)

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/s/ J. Brian Ferguson		Director
J. Brian Ferguson


/s/ William R. Loomis Jr.		Director
William R. Loomis Jr.


/s/ John E. Lowe		Director
John E. Lowe


/s/ Harold W. McGraw III		Director
Harold W. McGraw III


/s/ Glenn F. Tilton		Director
Glenn F. Tilton


/s/ Victoria J. Tschinkel		Director
Victoria J. Tschinkel


/s/ Marna C. Whittington		Director
Marna C. Whittington

139